LINE PROTECTION FOR A SAMPLED 230kV POWER SYSTEM
A Project
Presented to the faculty of the Department of Electrical and Electronic Engineering
California State University, Sacramento
Submitted in partial satisfaction of
the requirements for the degree of
MASTER OF SCIENCE
in
Electrical and Electronic Engineering
by
Christopher So
Tuan Hoang
FALL
2012
LINE PROTECTION FOR A SAMPLED 230kV POWER SYSTEM
Project
by
Christopher So
Tuan Hoang
Approved by:
__________________________________, Committee Chair
Turan Gonen
__________________________________, Second Reader
Salah Yousif
____________________________
Date
ii
Student: Christopher So
Tuan Hoang
I certify that these students have met the requirements for format contained in the
University format manual, and that this project is suitable for shelving in the Library and
credit is to be awarded for the project.
__________________________, Graduate Coordinator
Preetham Kumar
Department of Electrical and Electronic Engineering
iii
___________________
Date
Abstract
of
LINE PROTECTION FOR A SAMPLED 230kV POWER SYSTEM
by
Christopher So
Tuan Hoang
Statement of Problem
Our system involves two sample power plants which feeds power into three-phase
transmission line. A total of 10 generator/motor units, 10 power transformers, 7
transmission line sections, and 1 equivalent utility load are associated to the sample
power system. The goal is to determine the proper relay settings for distance and ground
overcurrent relaying on the present system configuration after in-depth fault analysis.
We will provide step distance protection and use an overcurrent relay as backup
protection for the sampled power plant. The expected results will give us line protection
for 230 kV transmission lines.
Sources of Data
We used outside sources such as books, articles, manuals, power industries software,
professor, and work material.
Conclusions Reached
In-depth fault analysis was conducted properly to set relay settings for distance and
overcurrent relaying on the sample power system configuration.
_______________________, Committee Chair
Turan Gonen
_______________________
Date
iv
TABLE OF CONTENTS
Page
List of Tables ............................................................................................................ viii
List of Figures ............................................................................................................... x
Chapter
1. INTRODUCTION. ……………..……………………………………………….. 1
2. LITERATURE SURVEY ………………………………………………………... 3
2.1 Line Protection ............................................................................................ 3
2.1.1 Voltage Classes ............................................................................ 3
2.1.2 Radial and Loop Systems............................................................. 5
2.1.3 Short Lines ................................................................................... 5
2.1.4 Typical Relaying Techniques ...................................................... 6
2.2. 21 Distance Relay ...................................................................................... 6
2.3. Overcurrent Relay .................................................................................... 13
2.4. Carrier Scheme......................................................................................... 17
2.5. Relay Coordination .................................................................................. 18
2.6. Reliability................................................................................................. 19
3. MATHEMATICAL MODEL ............................................................................... 21
3.1 System Characteristic................................................................................ 21
3.2 Fault Analysis ........................................................................................... 22
3.2.1 Z-Bus Matrix .............................................................................. 23
v
3.2.2 3 Phase and Single-Line-To-Ground Fault ................................ 25
3.3 Mho Relay Setting .................................................................................... 27
3.3.1 Coordination .............................................................................. 29
3.3.2 Applied Settings ......................................................................... 30
3.3.3 21Z1, 21Z2, 21Z3 Mho Relay Application-KD-10 Setting....... 35
3.3.4 PRC-023-1 ................................................................................. 35
3.4 Directional-Non Directional Ground Overcurrent Relay ......................... 37
3.4.1 Coordination .............................................................................. 39
3.4.2 Applied Directional-Non Directional Ground
Overcurrent Relay ...................................................................... 39
3.4.3 67N Directional Ground Overcurrent –Type IRQ Relay
Application. ................................................................................ 40
3.4.4 67 Carrier Directional Ground –Type KRQ Relay
Application................................................................................. 41
3.5 Directional Comparison Carrier Supervision............................................ 41
3.5.1 Applied Carrier Logic ................................................................ 42
3.5.2 85 Carrier Ground Start –Type KA-4 Relay Application .......... 42
4. MODEL APPLICATION AND RESULTS ......................................................... 44
4.1 Equipment Ratings .................................................................................... 44
4.2 System Impedances ................................................................................... 46
4.3 Sample 3-Phase Fault Study ..................................................................... 48
vi
4.4 Sample Single-Line-To-Ground Fault Study ............................................ 51
4.5 Distance (Mho) Relay Study Zone 1 ........................................................ 53
4.6 Distance (Mho) Relay Study Zone 2 ........................................................ 55
4.7 Distance (Mho) Relay Study Zone 3 ........................................................ 58
4.7.1 PRC-023-1 ................................................................................ 64
4.8 Ground Overcurrent Setting Study ........................................................... 70
4.8.1 Directional Carrier Ground (KRQ) Relay Setting .................... 73
4.8.2 67N Directional Ground Overcurrent (IRQ) Relay Setting ...... 74
4.9 Directional Comparison Blocking Carrier Logic Scheme ........................ 77
5. CONCLUSION ..................................................................................................... 79
Appendix A. MATHCAD SHEET FAULT STUDY .............................................. 81
Appendix B. EASYPOWER FAULT DATA ........................................................... 96
Appendix C. SYSTEM DIAGRAMS ..................................................................... 100
References ................................................................................................................. 104
vii
LIST OF TABLES
Tables
Page
1.
Table 4.1 Generator/Motor Units Electrical Specifications………………..…....44
2.
Table 4.2 Transformer Electrical Specifications..…………………………….....45
3.
Table 4.3 Transmission Line Electrical Specifications...……………………..…45
4.
Table 4.4 System Base Values…………………………………………………..46
5.
Table 4.5 Marriot Plant Equipment Impedance Data………………………….. .47
6.
Table 4.6 Alternate Plant Equipment Impedance Data ………………………....48
7.
Table 4.7 Utility Equipment Impedance Data ……………………………....…..48
8.
Table 4.8 Mathcad Calculations for 3-Phase Fault Study ……………...……… 50
9.
Table 4.9 Easypower and Mathcad Data Comparison – 3-Phase Fault …...……50
10.
Table 4.10 Mathcad Calculations for SLG Fault Study ……………………..…..52
11.
Table 4.11 Easypower and Mathcad Data Comparison – SLG Fault ………..….52
12.
Table 4.12 Zone 2 Setting System Configurations …………………………..…55
13.
Table 4.13 KD-10 Zone 2 Tap Settings ……………………………..………….58
14.
Table 4.14 Zone 3 Setting System Configurations ……………………………..59
15.
Table 4.15 PRC-023-1 Relay Settings...…………………………..…………….67
16.
Table 4.16 Mho Relay Settings………………………….....…………………...68
17.
Table 4.17 SLG Minimum and Maximum Fault Data …………………..……..71
18.
Table 4.18 Calculated Ground Instantaneous and Time-Overcurrent ………….73
viii
19.
Table 4.19 67 KRQ Relay Setting [21] ……………………………..………….74
20.
Table 4.20 67N IRQ Relay Settings…………………………..…………………75
ix
LIST OF FIGURES
Figures
1.
Page
Figure 2.1 Relay Connection to the Grid (a) and Balance Beam Type
Distance Relay (b)…………………...…………………………………………..8
2.
Figure 2.2 Impedance Diagram with Mho Circles ……………………………..10
3.
Figure 2.3 Various Distance Relay Characteristics …………………..………...10
4.
Figure 2.4 Type KD-10 Relay Chassis ……………………………….………...11
5.
Figure 2.5 Impedance Circle for Three Phase Unit in KD-10 Relay …………...12
6.
Figure 2.6 Impedance Circle for Three Phase Unit in KD-41 Relay..………….13
7.
Figure 2.7 Overcurrent Minimum Operating Criteria ………………………….15
8.
Figure 2.8 Inverse Time Characteristic …………………………..…………….16
9.
Figure 2.9 Directional Comparison Blocking ………………………………….18
10.
Figure 3.1 Current In-feed …………………………………………..………….32
11.
Figure 3.2 Zone 3 Protection …………………………………………..……….33
12.
Figure 4.1. Marriot, Alternate Plant, Equivalent Utility Power System ……….49
13.
Figure 4.2. Marriot and Equivalent Utility Power System Subject to
SLG Fault Study …………………...…………………………………………...51
14.
Figure 4.3. Line 1 and 3 Mho Circle – Zone 1, 2, 3…………………………….69
15.
Figure 4.4. Line 2 Mho Circle – Zone 1, 2, 3…………………………………...70
16.
Figure 4.5. Very Inverse Time-Overcurrent Curve [22] ……………………….76
x
17.
Figure 4.6. Directional Comparison Carrier Blocking Scheme ………………...78
xi
1
CHAPTER 1
INTRODUCTION
Protection systems such as relays play an important role in protecting the power system.
A protection system is a series of equipment including but not limited to: relays,
switches, batteries, auxiliary devices, meters, telecommunication devices, transducers, all
of which maintain the integrity and reliability of the bulk electric system. Short circuits
occur in power systems when equipment insulation fails due to system overvoltage
caused by mechanical or natural cause such as lighting. Currents can be several orders of
magnitude larger than normal operating current which can cause insulation damage, fire,
and explosion. The design, maintenance, and operation can minimize the occurrence of
short circuits but cannot eliminate them. Faults must be quickly removed from the power
system. A relay is defined as “A device whose function is to detect defective lines or
apparatus or other power system conditions of an abnormal or dangerous nature and to
initiate appropriate control action.” According to Blackburn, protection is defined as
“The science, skill, and art of applying and setting relays and/or fuses to provide
maximum sensitively to faults and undesirable conditions, but to avoid their operations
on all permissible or tolerable conditions” [1]. In this project we will focus distance and
ground overcurrent protection which are used to protect high voltage 230kV system.
Problems can occur within the protection equipment itself. For example faults that
occurs out of the range of a directional relay. Backup relays would be used as a second
line of defense to prevent protection equipment problems from happening. Backup
protection should coordinate with the primary relays that are assigned to protect
2
equipment in particular zones. It is important to coordinate relays because it is inefficient
to have multiple relays operating together. For our project, we will focus on distance
relay being the primary relay and an overcurrent relay as a backup relay. A distance relay
detects the change in impedance on a line by measuring the voltage and current flowing
through the line. An overcurrent relay operates or picks up when its current exceeds a
predetermined value. An overcurrent relay would operate as a backup to the distance
relay.
Our system involves two sample power plants which feeds power into two three phase
transmission lines. The goal is to determine proper relay settings for distance and ground
overcurrent relaying on the present system configuration.
3
CHAPTER 2
LITERATURE SURVEY
2.1 Line Protection
Line protection schemes associate the relative practices to provide adequate protection
for distribution or transmission lines. The typical consideration involved with line
protection include: line voltage classes, line length to consider voltage drop across the
entire line (SIR) surge impedance ratio, and radial or loop configuration.
2.1.1 Voltage Classes
The following voltage levels indicated below sets the criteria for lines categories:
•
Industrial distribution – 34.5 kV and lower
•
Sub-transmission – 34.5 – 138 kV
•
Transmission – 115kV and higher
o High voltage (HV) – 115 – 230 kV
o Extra high voltage (EHV) – 345 – 765 kV
o Ultra high voltage (UHV) – 1000 kV and higher.
In the distribution voltage range (34.5 kV and lower), lines ranging in 10-20 mile, are
connected from substations to various load densities ranging from industrial
loads/customers (some requiring three phase power tapped from all three phase lines),
business districts, and rural loads/customers. Protection provisions for the distribution
class of lines generally require outages to affect the fewest number of customers, device
4
settings to consider equipment and personal safety due to large currents in the low
voltage ranges, and an automatic restoration circuits to clear temporary faults and
reestablish service to customers. In specific applications with low voltages in the 480 –
120 V limit, fuses are the primary devices to disconnect a portion of the faulted zone
from the circuit, while circuit breakers and reclosers are typically applied at the
substation region. Reclosers and sectionalizers are other devices used in disconnecting
faulted zones.
The sub transmission classes (34.5 – 138 kV) are lines exposed between the transmission
and distribution voltage range which feed power through distribution substations, or feed
large loads directly from the generation level. The Protection provisions for this class
combine aspects of distribution and transmission classes which depends on the
configuration and level of importance.
The transmission line class (115kV and higher) functions as the interconnection between
multiple generating units, and medium to transport power to the substation where
distribution lines are connected. The protection provisions for this class involve fast
operation of protection devices, and only devices that are affected by the fault should
operate to isolate a zone. The settings for the protection devices should be calibrated to
allow short term loading conditions, and restores itself automatically for temporary faults.
Unlike the distribution class, circuit breakers are the main devices because they eliminate
arcing currents.
5
2.1.2 Radial and Loop Systems
Identifying radial and loop classifications for lines contributes largely to relay
coordination by implementing the appropriate time delays for the relay to operate. Radial
lines are defined with having one positive sequence source connected to one end and
loads connected on the other. In the case when the source on the line end is grounded, a
ground fault will result in current fed from one direction; unless both opposite ends of the
line are grounded. Eliminating the ground fault requires isolation of the source unit
without having to interrupt any equipment on the opposite line end. Loop lines differ
from radial lines by having sources connected to both ends of the line. Both ends of the
line must be isolated when a ground fault occurs since both ends will feed into the fault.
Mutual induction will facilitate zero sequence current in parallel lines for both radial and
loop lines and will require isolation of all ground sources.
2.1.3 Short Lines
Line lengths have three categories such as short (up to 50 miles), medium (up to 150
miles), or long (above 150 miles) lines. For fault studies there are special considerations
when applying the line length in determining fault currents near the beginning or far end
of the lines. This is due to the shunt capacitances of the lines, and their degree of
contribution to the fault current in short, medium, and long lines. A distinct property with
short lines is the advantage to neglecting shunt capacitances with the ground which
modifies calculations for self and/or mutually coupled line impedances. Long lines tend
to experience the Ferranti effect resulting in distorted actual fault impedance measured
through the distance relays, and operate the incorrect zone relay. Overcurrent relays are
6
also affected by the line length in terms of magnitude of current when a fault occurs on
any length of the line. This instance requires proper time delays between relays protecting
opposing ends of the line, including regards to radial or loop configured systems. In
addition to short lines which affect the settings of line protective relays, other influences
include: in-feed from tapped lines into other generating sources, considering fault
resistance in fault analysis, load encroachment, and multi-terminal lines where current
can traverse in multiple paths. Refer to [13] for additional information regarding line
length classifications.
2.1.4 Typical Relaying Techniques
The protective relays typically applied in all line classes due to their commutative
application for the distribution, sub-transmission, and transmission classes are: 1)
Distance, 2) Overcurrent, 3) Current Balance, and 4) Pilot communication schemes.
There are other properties with these relays such as directional and instantaneous or time
delayed operation that applies to their protective function. The first two relays will be
discussed in further detail to familiarize their function as this project relates to their
settings.
2.2 21 Distance Relay
Distance relays operate when the ratio between the measured system voltage and current
value is less than a preset value. The ratio represents the impedance of the line which is
then compared with a fixed impedance of the system. How the relay applies the voltage
7
and current properties towards initiating a trip status is explained through the function of
a balance beam type distance relay; currently out of production.
Similar to most electrical/mechanical protective relays still used in some utility systems,
magnetic induction and attraction is what generates the force that initiates the operation
from the voltage and current inputs to the distance relay. In the example of a balancebeam type distance relay, the principle of this type of relay utilizes induced forces from
electro-magnets produced from a measured voltage and current. Depending on where the
fault is located on the line, the measured voltage or current will be greater than the other,
and offsets the force produced by the measured voltage or current quantity. The induced
forces act on a balanced beam that is set on a pivot, and two electromagnets induced by a
voltage and current are position at both ends. Only when the current induced force
exceeds the voltage induced force, will the relay operate. The value of current and
voltage that operates the relay defines the impedance “balance point”, “operating
threshold”, or “decision point”. This impedance is a function of the distance on the line, a
property describing the reach of the relay.
8
Bus G
CT
Line, ZL
Relay
21
PT
(a)
Contacts
Pivot
V
I
(b)
Figure 2.1: Relay Connection to the Grid (a) and Balance Beam Type Distance Relay (b)
To represent the protection of a line, impedance diagrams will visually describe the
setting and characteristics of the relay, and used in coordinating with other neighboring
21 relays. Impedance diagrams show circles or various shapes signifying the reach for the
relay to operate. An example of a common type of impedance circle is a mho circle
(offset from the origin), which defines a range of measured impedance in a specific
direction to operate against faults. The direction of measured impedance depends on the
direction of current flow, or leading or lagging current, during a fault. Figure 2.2 shows
three mho circles on an impedance diagram with x and y axis representing a resistance
and reactance quantity, respectively. The three circles define the reach or protection
capability of each circle, indicating a zone of protection. The line extending from the
origin to point H is the measured impedance on a transmission line during a fault. The
mho circle zone 2 has a larger diameter than zone 1’s circle and is dependent on the CT’s
9
and PT’s turns ratio modified with a resistor; example IabZc, and line voltage, Vab. Zone 2
should be larger than zone 1 according to distance relay settings standards, and an
additional zone 3 should be even larger. This implies more of the line’s distance is
monitored by the relay. When faults are closer to the relay, the relay will measure larger
currents than voltage. For line faults farther away from the relay, the voltage will be
larger relative to the voltage close to the relay. The ratio of the two properties defines
where the fault falls within any three zones of protection. Measured impedances outside
any of the zones means relays will not operate. Zone 3 in a step-distance relay scheme is
used to provide remote back-up protection in the event of a failure of the protection
system that is normally expected to operate for the fault condition. In this particular
project, Zone 3 is set to look in the reverse direction with an additional 20% to 30% reach
beyond the protected terminal's Zone 2. A blocking instruction has to be sent by the
reverse looking relay elements to prevent instantaneous tripping of the remote relay for
Zone 2 faults external to the protected section. Otherwise there is the possibility of Zone
2 elements initiating tripping and the reverse looking Zone 3 elements will fail to see an
external fault. It is essential that the operating times of the relays be skillfully coordinated
for all system conditions so that sufficient time is allowed for the receipt of a blocking
signal from the remote end of the feeder. In order for this to happen, the reverse-looking
elements and the signaling channel must operate faster than the forward-looking
elements. From figure 2.2, zone 2 and 3 relay will operate with the measured impedance
located at point H. In order to prevent all three zones from operating at once, time delays
are set for zone two and three, and zone 1 will operate on the instantaneous setting.
10
X
Zone 3
distance
protection
H
Zone 2
distance
protection
Line
Zone 1
distance
protection
R
Figure 1.2: Impedance Diagram with Mho Circles
In regards to the mho circle as a type of impedance circle, there are numerous types used
in the industry that defines different protection capabilities, and discriminates against
operating on certain faults that induce measured impedances represented on the
impedance diagram. This includes but not limited to the following shown in figure 2.3:
Figure 2.3: Various Distance Relay Characteristics
11
Special applications involve the semi-plane type characteristics for distance relaying,
however the mho type characteristic is applied for the distance relay in this project. Refer
to [1] for determining relay reach mho circle calculations.
In this particular project, we are setting proper relay settings for Westinghouse KD-10
and KD-41. An illustration of the relay KD-10 is shown below.
Figure 2.4: Type KD-10 Relay Chassis
Application of KD-10:
The application for KD-10 relay is quite simple. The KD-10 type relay is a polyphase
compensator type relay which provides a single zone of phase protection for all three
phases. This relay provides instantaneous tripping for phase-to-phase, double phase to
ground, and three phase faults within the reach setting and sensitivity level of the relay.
12
Characteristic of KD-10:
Distance characteristics for phase-to-phase units: This unit responds to all phase-to-phase
faults and two-phase-to-ground faults. It does not respond to load current, synchronizing
surges, or out-of-step conditions.
Distance characteristics for three phase units: The three-phase unit has a characteristic
circle which passes through the origin as shown in Figure 2.5 [10]. This circle is
independent of source impedance. The three-phase unit is also inherently directional and
does not require a separate directional unit.
Figure 2.5: Impedance Circle for Three Phase Unit in KD-10 Relay
13
Application of KD-41:
The application of the KD-41relay is similar to KD-10 relay. This relay is applied as the
third zone of protection in pilot schemes. It may also be used for time-delayed tripping in
distance relaying.
Characteristic of KD-41:
Distance characteristics for phase-to-phase units is similar to KD-10 as stated above.
Distance characteristics for three phase units: The three-phase unit has a characteristic
circle which passes through the origin as shown in Figure 2.65 [9].
Figure 2.6: Impedance Circle for Three Phase Unit in KD-41 Relay
2.3 Overcurrent Relay
Overcurrent relay is a relay that operates or picks up when its current exceeds a
predetermined value. Lines are protected by overcurrent, distance, or pilot-relaying
14
equipment, depending on the requirements. Overcurrent relays are used for primary
ground-fault protection on most transmission lines where distance relays are used for
phase faults. Overcurrent relays are also for ground back-up protection on most lines
having pilot relaying for primary protection. Overcurrent or distance relays are the
primary when differential protection is not used. “Since faults produce an increase in the
phase and ground, overcurrent protection is widely applied to all voltage levels for all
currents in the system.” [1] Overcurrent relays are the simplest of all relay devices. Only
current needs to be measured to operate an overcurrent relay. An overcurrent relay uses
an electromagnet (a coil wire that becomes a magnet when electricity flows through it) to
link two circuits together. In general, when this circuit is activated, it feeds current to an
electromagnet that pulls a metal switch closed and activates the second output circuit.
The relatively small current in the input circuit thus activates the larger current in the
output circuit.
The input circuit is initially in the off position and no current flows through the circuit
until the closing of the switch turns it on. When a small current flows in the input circuit,
it activates and produces a magnetic field all around it. The energized electromagnet pulls
the metal bar in the output circuit toward it, closing the switch and allowing a much
bigger current to flow through the output circuit. The output circuit operates the trip coil
for the breaker. The minimum operating criteria for overcurrent relay is shown in Figure
2.7 [1] below.
15
Figure 2.7: Overcurrent Minimum Operating Criteria
Overcurrent relays may also operate instantaneously; with fixed or inverse time delays.
Instantaneous overcurrent relays activate with a small time delay, 16-20 milliseconds,
through induced forces to lift the solenoid. Inverse time characteristic is the combination
of producing fast operation at high current and slow operation at light current. This is
shown in Figure 2.8 [1] below.
16
Figure 2.8: Inverse Time Characteristic
The figure above shows the abscissa of the characteristic curves in multiples of tap or
pickup current. Typical inverse-time–overcurrent relay characteristic is typically
provided by the manufacturer. In general, all relays have several taps, each of which
represents the minimum current at which the unit will start to operate. This is also called
the minimum pickup value. For example, a current relay set on tap 5 will begin to operate
at 5.0 A, plus or minus the manufacturer’s tolerances. In addition to the taps, the spacing
for the contact travel is adjustable and marked by a scale known originally as a time dial.
Overcurrent relays have time dial settings that vary the time duration for the relay to
operate. Time dial provides different operating times at the same operating current level.
Transients in the current magnitude will affect rate of how the relay will operate. Most
17
instantaneous overcurrent or time-overcurrent relays will not start to reset until the
current drops below 60% of the pickup current.
Not only that, overcurrent relays are not directional. Measuring current gives no
indication of the current direction. Directional properties in relays apply current and/or a
reference voltage or current. The unit operates when the measured and reference quantity
are in phase. For this particular project, our power system is radial where the current of
flow is always known.
2.4 Carrier Scheme
Pilot protection is a type of differential protection for which the quantities at the terminals
are compared by a communication channel, rather than by a direct-wire interconnection
of the relay input devices [1]. Pilot protection schemes speed fault clearing time. A
variety of schemes such as Permissive Overreach Transfer Trip (POTT) and Directional
Comparison Blocking (DCB) have been developed to meet the requirements of
dependability, security, cost, and other factors. In this particular project, we focused
on Directional Comparison Blocking scheme. This is the most popular pilot
relaying scheme. This scheme is more dependable than permissive transfer trip
(POTT) scheme because it trips the breaker when there is no carrier signal from
the remote end pilot relay. Unlike permissive schemes that send a signal when a
fault is detected in the forward direction, DCB scheme sends a block trip signal
when a fault is detected in the reverse direction. An advantage of this scheme is
relays do not rely on trip signal from remote end substation to provide
18
protection for internal faults on transmission line. However, to check the
integrity of the communication channel, a test signal is transmitted.
Figure 2.9 below shows how a Directional Comparison Blocking (DCB)
operates.
Z3
Z2
Z1
L
R
Z1
Z2
Z3
Zone 3S
Loss of
Channel
TX
RX
RX
NOT
Delay
Zone 2S
Zone 3R
TX
NOT
AND
Trip S
Trip R
AND
Delay
Zone 2R
Figure 2.9: Directional Comparison Blocking
•
Local Breaker
o Reverse looking zone 3 elements sends a block trip signal if a
fault is detected.
o Zone 3 must exceed the reach of the remote terminal zone 2.
•
Remote Breaker
o Zone 2 element is allowed to high-speed trip after a coordinated
time delay unless a block trip signal is received.
2.5 Relay Coordination
Relay coordination plays an important role in protection. Proper application and
coordination of over-current relays and other protective devices is vital in a system
19
requiring reliable electrical service. The proper selection and coordination of protective
devices is mandated in article 110.10 of the National Electrical Code. “The overcurrent
protective devices, the total impedance, the component short-circuit current ratings, and
other characteristics of the circuit to be protected shall be selected and coordinated to
permit the circuit-protective devices used to clear a fault to do so without extensive
damage to the electrical components of the circuit. This fault shall be assumed to be
either between two or more of the circuit conductors or between any circuit conductor
and the grounding conductor or enclosing metal raceway. Listed products applied in
accordance with their listing shall be considered to meet the requirements of this section.”
One important device that distance relays require is a voltage source. “Three-phase
voltage is required and provides reference quantities with which the currents are
compared.” [1] Phase distance relays require coupling capacitor voltage transformers
which is also known as CCVTs to be connected either to bus or to the line that is
protected. A loss of one or more phase voltages may result in an unwanted relay
operation. To prevent this from happening, overcurrent fault detectors can be added to
supervise the trip circuit of the distance relays. One down fall for overcurrent fault
detector is overcurrent units would not operate for a loss of voltage in the absence of an
actual fault.
2.6 Reliability
Reliability of a protective system is defined as the probability that the system will
function correctly when required to react. “It is important that the protective system be
designed with due regard for its own unreliability.” [Anderson pp.8] This means that the
20
backup protective system should be installed to operate in case the primary protective
equipment fails so that system damage could be minimized and restoration of normal
service can be achieved quickly. Local back up relays are an alternate set of relays in a
primary protection zone that operate under prescribed conditions in that protection zones.
Backup protection and redundancy is crucial in system protection. According to
Blackburn, “Backup is defined as protection that operates independently of specified
components in the primary protective system. Backup up protection may duplicate the
primary protection, or may be intended to operate only if the primary protection fails or is
temporarily out of service.” [1] If the independence is not provided, there is the
possibility that a failure in the protection will prevent the opening of the local breakers to
clear the fault. Clearing the fault under these circumstances could be achieved only by
backup protection.
Time solution is a key factor when working with relays. Setting criteria is intricate when
coordinating primary and backup relays. Delays are applied to relays to allow the primary
protection to operate first. Settings must ensure that the phase and ground protection do
not operate in the back up area until the primary phase and ground protections assigned to
that area have the opportunity to clear the fault. The objective is to set the protection to
operate as fast as possible for faults in the primary zone, yet delay sufficiently for faults
in the backup zones. “The settings must be below the minimum fault current for the relay
to operate, but not to operate on all normal and tolerable conditions.” [1]
21
CHAPTER 3
MATHEMATICAL MODEL
3.1 System Characteristic
(Refer to figure C.1 in Appendix C to follow along with the description of the plant) The
Marriot is a hydro pumping/generating plant consisting of pumping and generating units
to offset some of the cost to pump water up a head of approximately 600ft. Three out of
the six units are pumping/generating units, while the other three units are synchronous
hydro generators. Ratings of all equipment will be introduced in chapter 4. Each unit is
connected to a wye-delta three-phase transformer which steps up the voltage to 230kV.
Each transformer is connected to the Marriot main-transfer bus scheme switchyard
through a 2400 foot long three phase pipe-type cable circuit. The purpose for this
configuration is to allow multiple paths for current to flow to the pumping/generating
units in the event that one out of the three transmission lines connecting into the plant
were to be removed out of service. The main bus is sectioned into three groups using two
sectionalizers (1061 and 861), and connected to a circuit breaker. The transfer bus
breakers (788, 564, and 266) are normally open until power is redirected away from one
line, and in some instance these breakers are closed such that current flows away from
out of service main bus breakers. Energizing the transfer bus is also used for pumping
units during low frequency startup. The main bus breakers are 266, 265, 264, 263, 262,
and 261. Transmission line breakers 2161, 269, and 267 are also connected to the main
bus. The three sets of 230kV three-phase transmission lines extending out of the plant are
22
identified with the following ID’s: Melanie Line 1, Johnson Line 2, and Bell Line 3.
Alternate Plant is a neighbor to the Marriot plant, and taps into the utility substation
through lines 1 and 3. Since Alternate Plant and Marriot plants are separate entities, the
only information regarding the Alternate Plant is their power injection to the associated
lines 1 and 3. Restrictions on the plant include the provision that two units may only feed
into one of the transmission lines, and their feeding order is determined as: 1) Line 1 is
fed by units 1 and 2. 2) Line 2 by units 3 and 4, and 3) Line 3 by units 5 and 6. Line
loading restrictions are also set for certain times of the year to account for the thermal
ratings of the transmission lines. Alternate Plant has 2 tapped lines; one going to Melanie
Line 1 (tap 1) and the other going to Bell Line 3 (tap 3). A restriction on the Alternate
Plant is only one transmission line tap 1or tap 3 is in service for typical operating
conditions.
3. 2 Fault Analysis
The fault studies are implemented to determine relay settings limitations on the protection
criteria’s, and determine adequate settings due to special conditions based on system
configurations. Equipment ratings are collected from equipment nameplate data, and
converted to per unit impedances. The fault studies will be performed through forming
the Z-bus matrix to circumvent typical network reductions through circuit analysis, and
facilitate computations. The general procedures to forming the Z-bus matrix and
performing systematic fault analysis are described below.
23
3.2.1. Z-Bus Matrix
The simplified properties of the Z-bus matrix are as follows:
•
The Z-bus matrix dimensions for a system with “n” buses will be n x n.
•
The diagonal elements in the Z-bus matrix constitute the thevenin equivalent
impedance of the system with respect to the element’s row and column. Example:
Matrix element, Z2,2 , is the thevenin equivalent impedance of the system with
respect to bus 2.
•
Forming the matrix involves determining the connections between buses through
a branch or links (transmission lines, cables, a transformer with two buses on the
primary and secondary winding, etc.)
•
In fault analysis, the positive, negative, and zero sequence impedances is
represented by their own individual Z-bus matrix (i.e. Z0matrix, Z1matrix Z2matrix).
The procedure to forming the Z-bus matrix is proposed by following 3 rules:
1. Rule 1: Grounded equipment attached to Bus/nodes – Begin forming the matrix
by including equipment impedance values connected to the reference bus
(ground). Begin forming the Z-bus matrix with the following elements,
Znew
bus
 Z11


= 
 Z m1

 0
 Z1m
 0
 Z mm
 0
0

0
0

zq 0 
(3.1)
24
where Z11 and Zmm represents equivalent equipment impedances connected to bus
1 or bus m, respectively.
zq0 = additional equivalent equipment impedance connected to bus q.
2. Rule 2: Adding new bus with a branch to existing bus – The next rule accounts for
all remaining buses not represented from rule 1. The impedance between the new
and old bus is represented by the off-diagonal elements depending on the system
configuration (i.e. transmission line connects bus a and b, defining the impedance
between bus a and b, Zab). The addition of new buses interconnected with existing
buses modifies the previous Z-bus matrix from rule 1 to the following model;
considering the addition of line impedance, zpq, between old bus p, and new bus q.
new
Z bus
 Z11

 
Z
=  pp
 
Z
 m1
 Z p1
 Z1 p


 Z1m


 Z pp  Z pm




 Z mp  Z mm
 Z pp  Z pm



Z pp 



Z mp 

Z pp + z pq 
Z1 p

(3.2)
where zpq is the impedance to be added between old bus p, and new bus q.
Elements represented with upper case Z, defines matrix elements from the
pre-modified matrix.
3. Rule 3: Adding branch between two existing buses – This step considers all
connections between buses developed from rules 1 and 2. The equation to include
25
a branch (i.e. transmission line connection ) zpq between existing buses p and q is
shown as,
old
Znew
bus = Z bus -
ΔZ ⋅ ΔZT
Zll
(3.3)
where
Zll = z pq + Z pp + Zqq - 2Z pq
(3.4)
 Z1q


Z
ΔZ =  pq
 Z qq


 Z mq
(3.5)
and,
- Z1 p 



- Z pp 

- Zqp 



- Zmp 
where zpq is the impedance connected to bus p and q, and “Z” elements pertain to
the previous Z-bus matrix .
3.2.2 3 Phase and Single-Line-To-Ground Fault
The fault studies will apply 3-phase and single-to-ground fault data to determine specific
values for the distance and ground relays settings. This can be accomplished with the
developed Z-bus matrix of the system’s positive, negative, and zero sequence impedances
(Z0matrix, Z1matrix Z2matrix).
3-phase faults only apply the positive sequence impedances due to its symmetrical
current characteristic. To determine the fault current on a faulted bus, k, is determined as,
26
I 31− phase,bus k ( f ) =
Vf
Z
1
k ,k
+ Zf
(3.6)
where Z1k,k is the positive sequence Z-bus element from row k, column k, and Zf is the
fault impedance (this value is omitted to consider the case of highest fault current).
1
Single-line-to-ground fault current at bus k, I SLG
,bus k ( f ) , is calculated below as,
1
I SLG
,bus k ( f ) =
Vf
Z
1
k ,k
+Z
2
k ,k
+ Z k0,k + Z f
(3.7)
where Z2kk and Z0kk are the negative and zero sequence Z-bus matrix elements from row
k, column k, respectively.
Fault studies with the Z-bus matrix simplifies the process in analyzing multiple fault
cases on various buses, and allows matrix evaluations to calculate the magnitudes of bus
voltages and fault currents throughout the system. Determining sequence bus voltages,
Vi0, Vi1, Vi2 , on bus i, due to a fault on bus k with sequence fault currents,I0k , I1k , I2k , is
provided as,
Vi 0   0 − Z ik0 I k0 
 1  1
1
1
Vi  = Vi (0) - Zik ⋅ I k 
Vi 2   0 − Z ik2 I k2 
  

(3.8)
where Vi1(0) is the positive sequence pre-fault voltage on bus i (typically 1 PU), and
Zik0,1,2 is the Z-bus matrix element on row i, column k. The values of the sequence
current, Iij0, Iij1, Iij2, flowing through line connection between buses i and j can be
calculated as,
27
 Vi 0 − V j0 


0
 zij 
0
 I ij   1
1 
 1   Vi − V j 
=
I
 ij   z1 
ij
 I ij2  

 
Vi 2 − V j2 


2
 zij 
(3.9)
Ground fault distribution current, 3I0, through line connection between bus I and j due to
ground fault is defined as,
I groundfault = Iaij + Ibij + Icij = 3I ii0
(3.10)
ij
Fault current distribution through transmission lines will be useful towards distance and
ground overcurrent settings; current through CT inputs to each relay will dictate the tap
settings towards each application.
3.3 Mho Relay Setting
Typical transmission line protection schemes for short line applications include current
differential, phase comparison, permissive overreaching transfer trip (POTT), and
directional comparison blocking [15]. The current differential application is to address
issues discriminating between fault currents due to close-in faults and line end faults [1].
However, cost considerations and disturbance factors associated with differential
protection includes: six pilot conductors including neutral and DC connections if
applicable, cabling with heavy insulation if exposed to outside weather, errors relating to
CT saturation, and transmission line charging current and voltage drops due to line
lengths and large secondary currents [12]. The aforementioned concerns with differential
relaying for transmission lines have limited its application to line lengths less than two
28
miles. Mho relaying is preferred for primary protection of 3-phase and line-to-line faults
for transmission lines up to at least ten mile in length. Distance relaying is also applied in
generator backup protection and briefly described to have the following general settings
criteria:
•
1.5 – 2 times the generator(s) MVA rating at rated power factor, but this setting
should be analyzed for de-sensitivity to line faults [19].
•
For Generator thermal protection: 50% - 66.7% of load impedance (200% - 150%
generator capability curve) at rated power factor angle.
•
Applied in Generator protection - 80% - 90% load impedance at (125% - 111%
generator capability curve).
•
Zone 1 and 2 relays consists of a time delayed function longer than the associated
unit, transformer, bus, transmission line, and breaker failure relays, respectively.
•
Extreme system loading or stable swings should not cause naissance false
tripping or interrupt normal generator loadability
Typical mho distance specifications (not necessarily applied to Marriot’s system
configuration) observed and used in industry applications include:
•
Settings coordinated with transmission owner regarding setting and time
coordination.
•
For some system configurations such as in-feed, other means of protection must
be applied aside from distance relays which necessitate overlapping between
zones of protections.
29
•
Fundamentals for setting mho protection is the following (radial lines):
o Zone 1 set to 85-90% of positive sequence line impedance intended for
instantaneous operation [1].
o Zone 2 50% beyond the next adjacent line including a time delay, T2. [1],
or 120% of longest line with in-feed [19].
o Zone 3 (if applicable) 25% to adjacent line beyond with a time delay, T3
[1].
o A general rule for coordinating between primary to secondary, and
additional back-up relays is allow .2 sec (12 cycles) plus the coordinating
time interval (CTI, typically .3 sec or 18 cycles is frequently used) for the
far-bus fault [1].
When applying distance protection with multi-terminal transmission lines, such as
Marriot’s line configuration, is best protected with pilot relaying, and can mitigate relay
redundancy and delayed fault clearing conditions [1, 15].
3.3.1 Coordination
The following concerns regarding coordination with mho relay settings include:
•
Distance relay as back-up generator protection must coordinate with generator
excitation protection (over-excitation limiter, voltz per hertz limiter).
•
Application of line or generator protection, generator and transmission owners
should approve of applicable settings and time delays between equipment.
30
•
Any settings modifications between one transmission/generation owner(s) will
require validation with other transmission/generation connected owner(s).
•
Transmission line impedance data on generator high side, and relay settings should
be exchanged between generator and transmission owner.
•
Coordinating pilot protection functions with distance relay associated tripping on
multi-terminal lines can mitigate over-reaching adjacent protection zones at remote
ends when in-feed sources are removed.
3.3.2 Applied Settings
The transmission system for the sample power system is categorized with three zones of
protection. Zone 1 protection relates to fault sensing approximately 90% of the
transmission line between Marriot plant and either the Utility Bus or Alternate plant.
Zone 2 protection is fault sensing of the entire transmission system between Marriot and
Utility bus and Alternate plant together, with a small margin beyond the two remote
buses. Zone 3 protection is reverse sensing, and looks into Marriot switchyard and
possibly into the step-down transformers. Based on in-feed properties present in
Marriot/Alternate Plant/Utility shared transmission system, the settings standard will
consist of the following:
•
Zone 1 forward looking setting is the primary line protection for 3-phase and lineto-line faults. All phases should be isolated from the fault to protect the generating
units rated for 3-phase power operation. Zone 1 settings are set for K times the
lowest actual impedance to any remote terminal [15]. As the primary line
31
protection, no intentional delay is set, and should operate within 1 – 2 cycles. The
value of K is typically 80-90% percent of the shortest line impedance between the
local bus and any remote buses. Because the KD-10 refers to 90% as the default
calculation [10], the value of K for zone 1 setting will be,
Kzone1 = .9
(3.11)
Zone 1 setting will be based on the line connecting from any Marriot bus to the
utility bus since the line distance between Marriot plant and Utility Bus is the
shortest. Zone 1 setting is determined as.
Zzone1 = K ⋅ ( ZTL Marriot bus - tap 1 or 3 + ZTL tap 1 or 3 - Utility )
(3.12)
or in terms of secondary impedance,
Zzone1secondary = Z zone1 ⋅
CTR
PTR
(3.13)
where CTR and PTR are the input CT and PT ratio’s to the relay.
•
Zone 2 forward looking setting as back-up protection for zone 1 detecting 3-phase
and line-to-line faults will consider effects of in-feed, and set 120% of the largest
apparent impedance seen on the longest line impedance between the local bus
(Marriot) and any remote bus (Alternate plant) [12]. This method of setting
considers the possibility of over-reaching the remote buses’ zone 1 setting in
absence of pilot protection when Alternate plant‘s in-feed effects is disconnected
from the tap line. A typical time delay of 20 (.33 sec) to 30 cycles (0.5 sec) is
applied to allow coordination with Marriot, alternate plant, and utility buses zone 1
operation [5]. Figure 3.1 describes the in-feed effect from a fault condition, and
32
including additional generation plant taped onto a line. Further sections will
discuss Zone 2 supervision through directional comparison blocking scheme.
Fault
Ia
Za
Ic
Zc
a
c
Ib
Zb
b
Figure 3.1: Current In-feed
Equation for apparent impedance, ZR, of a line seen by the relay located at breaker
“a” is defined as,
ZR =
Ea
I Z + I c Zc
= a a
,
Ia
Ia
(3.14)
where Ia and Ic are line currents shown in figure 3.1. Use equation 3.14 to convert
to an secondary impedance, and the final zone 2 setting becomes,
Z Zone2 = 120% ⋅ (Z R )
(3.15)
Johnson Line 2 does not consists of taps on its line, and its zone 2 setting is,
Line 2
ZZone2
= 120% ⋅ (ZZ.1 _ TL.L2.Marr )
(3.16)
33
•
Zone 3 is commonly used in a Permissive Overreach Transfer Trip (POTT)
communications scheme. In this particular project, we focused on
Directional Comparison Blocking (DCB) scheme. This is the most
popular pilot relaying scheme. This scheme is more dependable than
permissive transfer trip (POTT) scheme because it trips the breaker when
there is no carrier signal from the remote end pilot relay. Unlike
permissive schemes that sends a signal when a fault is detected in the
forward direction, DCB scheme sends a block trip signal when a fault is
detected in the reverse direction. Section 4.9 will explain in-depth on the
carrier scheme.
From figure 3.2 below, the zone 3 element reach at breaker 1 must be selected to detect
all out-of-section faults also detected by the overreaching elements at breaker 2. At a
minimum, Zone 3 reach setting must equal the impedance of the overreaching element at
breaker 2. If Zone 2 reach for the line protection at breaker 2 is set for 120% of the line
impedance, Zone 3 reach at breaker 1 is set at 120% of the Zone 2 overreach from
breaker 2.
Z2
Z1
1
2
Z1
Z2
Z3
Figure 3.2: Zone 3 Protection
The requirements for Zone 3 calculations are provided below,
•
Line impedance of the protected line
34
•
Zone 2 setting of the remote relay
•
CT ratio of and PT ratio of both local and remote relay
Below shows the basic steps that are needed to calculate reverse Zone 3 setting. Please
refer to Figure 3.2 as a reference.
1. Calculate Zone 2 setting of the remote relay. Zone 2 at breaker 2 has a set reach of
120%. The effective reach can be calculated as
Z2Breaker2 =1.20× line impedance
(3.17)
2. If Zone 2 setting is in secondary ohm, convert to primary ohms using provided
CT ratio and PT ratio.
3. Breaker 2 overreach is equal to Breaker 2 Zone 2 setting minus the line
impedance.
Breaker 2Overreach = Z2Breaker2 - line impedance
(3.18)
4. Zone 3 Breaker 1 is equal to 120% of Breaker 2 Zone 2 overreach. Therefore,
Zone 3 reach can be calculated as
Zone 3Reach = 1.2 × Breaker 2Overreach
(3.19)
5. Convert Zone 3 reach to secondary ohms using the provided CT ratio and PT
ratio.
Even though we were unable to get transformer protection data, Zone 3 time delay will
coordinate with the transformer protection to avoid over tripping. A common practice is
35
to set the zone 3 reach with a 60-cycle time delay, provided that it does not reach beyond
any zone 2 setting of the remote station’s line sections.
Setting Zone 3 on the electromechanical KD-41 relay is quite simple. For zone 3 reverse
tripping direction, the primary step is to reverse the current connection meaning swap the
lead coils. This will allow the relay to see in the reverse direction for reverse zone 3
faults.
3.3.3 21Z1, 21Z2, 21Z3 Mho Relay Application - KD-10 Setting
The procedure to implementing zone 1-3 impedance settings to KD-10 relays is provided
in the associated manufacture leaflet [10]. Internal relay settings include adjustable
compensator tap setting, T, auto-transformer primary tap, S, and auto-transformer
secondary tap setting, M [10]. The three adjustable settings is applied in the equation
representing the impedance setting referenced on the CT and PT secondary side:
ZSetting(Secondary) =
S⋅T
1 ± M
.
(3.20)
The value from equation 3.20 should be within 1.5% of the calculated setting from
section 3.3.3, or select alternative relay settings to produce a closer margin [10]. Other
KD-10 relay settings will not be discussed in this application.
3.3.4 PRC-023-1
Federal Energy Regulatory Commission (FERC) issued the Transmission Relay
Loadability standard in May 2009 to approve PRC-023. FERC stated that “The 2003
blackout report cited Zone 2 and Zone 3 relays tripping for overload and stable power
swings, instead of faults, as a major contributor to the blackout.” [11] This blackout
36
report mandated that all Zone 3 relays on lines operated at 230kV and above must be
reviewed to ensure that the relay would not operate for extreme emergency loading
condition.
Transmission relay loadability requires transmission owners to follow criteria to prevent
its phase protective relay settings from limiting transmission system loadability while
maintaining reliable protection of the Bulk Electric System for all fault conditions.
“Protective relay settings shall not interfere with system operator taking remedial action
to protect system reliability.” [11] Protective relay settings should be set to reliably detect
fault conditions and protect the system from faults. If the relay settings that protect the
Bulk Electric System are more limiting than the Facility Rating, then the Facility Rating
need to reflect this constraint. Some applicable relays are: phase distance, over current,
communication-aided protection schemes, and switch-on-to-fault just to name a few.
Relays that are not applicable are: ground fault, generator relays that are susceptible to
load, and relays in special protection scheme just to name a few.
PRC -023 states each transmission owner shall evaluate relay loadability at 0.85 per unit
voltage and a power factor angle of 30 degrees. Requirement R1.1 mandates transmission
owners to set line relays to not operate below 150% of the highest seasonal facility rating
duration nearest to a 4 hour interval. Certain requirements are needed to calculate PRC023-1. These requirements are listed below,
•
Line voltage
•
Line Rated Current
•
Line Loading MVA
37
•
Line impedance angle
Calculation of PRC-023-1 is defined as,
Zrelay =
.85VLL
1.5× 3×I rating
(3.21)
PRC-023-1 equation can be re-written as:
Zrelay =
2
.85VLL
1.5MVA[cos(θ-30° )]
(3.22)
To get MVA,
Line loading MVA = 3 × I rating × VLL
(3.23)
The above criteria will prevent phase protective relay settings from limiting transmission
system loadability while maintaining reliable protection of the Bulk Electric System for
all fault conditions.
3.4 Directional-Non Directional Ground Overcurrent Relay
Principle operating quantity for ground overcurrent relays of the directional or nondirectional type is dependent on zero sequence currents contributed from, system stability
swings, unbalanced loads, or ground faults. Some system applications utilize ground
overcurrent relays as the primary protection against single-line (SLG) and double-line-toground (DLG) faults. Directional relays, through negative sequence polarizing quantities
(V2 or I2), applies protection concentrated in one direction, with taps defining the distance
of the zone of protection. These relays are typically required for lines consisting of a
weaker source at its receiving end. Non-directional elements offer similar protection
38
without polarizing quantities. General settings for ground overcurrent relays apply
selective operations for primary zones of protection, and delay action for faults in backup
zones. Typical settings regarding directional and non-directional types include:
•
Ground settings are 1/5 to 1/10 of the phase relay settings, and consist of
instantaneous and time delayed operation [14].
•
In general, close in faults induce higher fault current distribution with respect to
the local bus than faults at the end of the transmission line. Line lengths and source
impedances can influence the fault magnitude for internal and external faults.
•
Instantaneous settings are established by fixing the tap higher than the maximum
fault current due to faults external of the protected line. This also ensures
coordination with time overcurrent pickup settings, and defines parameters for
backup protection with time delay settings [15]. Instantaneous settings should only
actuate for internal ground faults (close to the local bus) up to the remote bus. For
instances with transmission lines with taps, actuation should be permitted up to the
location of the tap [18].
•
Time-overcurrent pickup settings should inhibit tripping on max loading
conditions and temporary unbalances. Coordination should be based on protection
in-front of the directional relay, or protection in both forward and reverse
directions for non-directional relays. Similar relay characteristics (inverse or veryinverse) should be used for coordination purposes with similar downstream relays.
Time-overcurrent settings should only operate for ground faults on or near the
39
remote bus; only after the protective relays on the remote bus has the opportunity
to clear the fault [18]
3.4.1. Coordination
Coordinating provisions are similar to what is stated in section 3.3.1 mho distance
relaying. However the time-overcurrent settings should use time curves similar to other
time-overcurrent relays to limit miss-coordination between zones of protection [18].
3.4.2. Applied Directional-Non Directional Ground Overcurrent Relay
The three zones of protection also apply for ground overcurrent relays as alluded to
section 3.3.2. Applying directional quality relays will concentrate ground fault clearing
actions for specific protection zone (with carrier supervision). The following criteria for
directional and non-directional ground overcurrent relays, respectively:
•
Residual currents of phase CT’s, 3I0, is based on single-line-to-ground fault
studies, and should be considered in ground settings [1].
•
Instantaneous setting is “k” times the maximum far bus fault current, or a fault at
the tap location [1]. The range of “k” is typically set between 1.1 – 1.3, however
1.2 will align with zone 2 protection limits. In terms of secondary current, the
𝐿𝑖𝑛𝑒
instantaneous setting, 𝐼𝐼𝑛𝑠𝑡𝑎𝑛.
, is determined as
Line
I Instan.
= k ⋅ I base ⋅ 3I0max ⋅ 1
CTR
(A)
(3.24)
where CTR is the input current transformer ratio to the ground overcurrent relay.
40
•
In carrier ground relay applications such as directional comparison blocking
scheme, tap sensitivity should be less than the remote bus settings. Ground fault
studies should show the minimum ground fault induced in protected line is three
times the tap value current [5], it’s operating quantity is on sensitive ground faults
•
Typical ground time-overcurrent pickup setting (directional or non-directional)
can be set to 0.5-1 A tap, however the calculated minimum ground fault, 3I0,
distributed in the line should be at least three times the relay tap value to verify
applicability [5]. This verification may not always be applicable, and depends on
the coordination of associated relays used as primary or backup protection. In
terms of secondary current, the pickup setting is represented as,
Line
0
1
ITime
O. = I base ⋅ 3I min ⋅
CTR
(A)
(3.25)
and can be compared with the 0.5A tap pickup setting for verification.
Referenced fault data is provided according to equations in section 3.2.2. The carrier
blocking pilot scheme is described in the following section.
3.4.3 67N Directional Ground Overcurrent – Type IRQ Relay Application
The type IRQ relay is a directional overcurrent negative sequence ground protection
relay, for applications where zero sequence quantities are not reliable polarizing
quantities due to mutual coupling from parallel lines [18]. An instantaneous and timeovercurrent unit within the IRQ relay allows differences between close-in and remote
ground faults. Setting the time-overcurrent unit requires a tap setting and time dial
position, describing the operating characteristics of the unit. The instantaneous unit only
41
requires a pickup setting. Characteristic time curves for the time-overcurrent unit ranges
from short time to extremely inverse. For consistency and better coordination between
downstream overcurrent relays at Marriot plant, the very inverse curve will be used.
3.4.4 67 Carrier Directional Ground – Type KRQ Relay Application
Similar to the 67N IRQ relay, however the KRQ only has instantaneous settings, and
functions as a carrier start relay in pilot protection. The application of this relay is
intended for zone 1 primary protection of ground fault, 3I0, instances. Relay settings will
be applied in section 4.8.1.
3.5 Directional Comparison Carrier Supervision
Pilot protection has in transmission line protection as portion of coordination and method
to. For mho distance relay applications, the pilot scheme renders a transfer signal to a
remote bus based on fault current comparison between the local and remote buses. The
pilot scheme will discern between internal and external faults from the local bus. Pilot
schemes are generally unique to each generation and owner, and apply to the type of
relaying implemented for each zone of protection. Typical guidelines for applications
from
•
Directional comparison schemes will accompany directional distance relays (mho)
and directional ground overcurrent relays.
•
Pilot assisted zone 2 settings will not trip faults effecting adjacent equipment, and
therefore does not usual require time delay settings or coordination.
42
•
Directional ground relays operate nearly instantaneously in pilot schemes, however
under-reaching overcurrent relays should actuate instantaneously. General rule for
ground overcurrent relays is to set quite sensitive.
•
Directional schemes for over-reaching distance and ground overcurrent relays will
prevent operation from external faults.
•
Reverse looking pilot schemes at a local bus should extend protection beyond
forward over-reaching protection from a remote bus. Adequate margins should
consider the current dividing into tapped lines, or multi-terminal lines [15].
3.5.1 Applied Carrier Logic
Components of the pilot protection system or communication mediums will not be
discussed, however the function and logic to describe the relay operation is discussed in
figure 4.6. Section 2.4 describes the basic principle of operation for directional
comparison blocking schemes.
3.5.2. 85 Carrier Ground Start – Type KA-4 Relay Application
The carrier ground start relay is a component of the pilot scheme that initiates the
blocking signal to the remote buses for faults internal to Marriot bus sections. As backup
protection for downstream devices, this relay should sense the lowest ground fault
current, 3I0, flowing in the direction of Marriot plant to prevent nuisance instantaneous
tripping on external faults (effecting Marriot plant only) by the remote bus. The carrier
signal should be actuated without intentional delay to allow downstream protection to
clear the fault. Adjustable or calculated pickup values are not required for this relay.
43
Coordination with remote bus directional carrier starts is necessary, similar to the
directional carrier start (67) relay at Marriot plant intended to be blocked for external
faults. Typical operating current for this relay is 0.5 A actuating from ground fault
currents, 3I0 [5].
44
CHAPTER 4
MODEL APPLICATION AND RESULTS
4.1 Equipment Ratings
A total of 10 generator/motor units, 10 power transformers, 7 transmission line sections,
and 1 equivalent utility load are associated to the sample power system. Station service
loads are omitted due to their small contributions to fault current values on the 230kV
transmission level. The rated specification for each component is described in the
following tables below.
Table 4.1: Generator/Motor Units Electrical Specifications
Plant
Equipment
Type
MVA
kV
rated
pf
X/R
Xd"(%)
Xd'(%)
X0(%)
Marriot
Unit 6,4,
and 2
Synchronous Salient Pole w/
Amortisseur
Winding
115
12.5
0.85
95.90
21
28.2
16.1
Marriot
Unit 5 and 3
Synchronous Salient Pole w/
Amortisseur
Winding
123.16
12.5
0.95
117
23.5
27
12.95
Marriot
Unit 1
Synchronous Salient Pole w/
Amortisseur
Winding
123.16
12.5
0.95
99.24
23.5
27
12.95
A.P.
Unit 4,3,
and 2
Synchronous Salient Pole w/
Amortisseur
Winding
30.555
13.8
0.8
50.39
30
38
18
A.P.
Unit 1
Synchronous Salient Pole w/
Amortisseur
Winding
34.316
13.8
0.9
53.11
30
37
21
Note: A.P. – Alternate plant.
45
Table 4.2: Transformer Electrical Specifications
Plant
Equipment
Mar.
Trf. K1A
Mar.
Trf. K2A
Mar.
Trf. K3A
Mar.
Trf.K4A
Mar.
Trf. K5A
Mar.
Trf. K6A
A.P.
Trf. 4
A.P.
Trf. 3
A.P.
Trf. 2
A.P.
Trf. 1
Type
FOW-force oil and
water
FOW-force oil and
water
FOW-force oil and
water
FOW-force oil and
water
FOW-force oil and
water
FOW-force oil and
water
Wye-g / Delta OA/FA
Wye-g / Delta OA/FA
Wye-g / Delta OA/FA
Wye-g / Delta OA/FA
MVA
Turns
ratio
(kV)
Tap
Setting
X/R
Ratio
Z
(%)
Z0 (%)
127
230/12
230/12
39.66
14.1
11.985
127
230/12
230/12
39.66
13.78
11.713
127
230/12
230/12
39.66
13.9
11.815
127
230/12
230/12
39.66
14.08
11.968
127
230/12
230/12
39.66
14.08
11.968
127
230/12
230/12
39.66
14.1
11.985
24.4
230/13.2
235.75/13.2
24.03
9.9
8.415
24.4
230/13.2
235.75/13.2
24.03
10
8.5
24.4
230/13.2
235.75/13.2
24.03
9.9
8.415
26.25
230/13.2
230/13.2
24.69
9.8
8.33
Note: A.P. – Alternate plant, Mar. = Marriot plant, Trf. = Transformer
Table 4.3: Transmission Line Electrical Specifications
Plant
Equipment
Mar.
Line 1 –
Mar. to Tap
Line 2 –
Mar. to
Utility
Mar.
Line 3 –
Mar. to Tap
Uty.
Line 1 - Tap
to Uty
Uty.
Line 3 - Tap
to Uty
A.P.
Line 3 - Tap
to A.P.
A.P.
Line 1- Tap
to A.P.
Mar.
Type
ACSR 1113
BlueJay
ACSR 1113
BlueJay
ACSR 1113
BlueJay
ACSR 1113
BlueJay
ACSR 1113
BlueJay
ACSR 1113
BlueJay
ACSR 1113
BlueJay
Rated
Current
kV
Length
(mi)
R1
(Ω/
mi)
X1
(Ω/
mi)
R0
(Ω/
mi)
X0
(Ω/
mi)
Xc
(MΩ
/mi)
Xc 0
(MΩ
/mi)
1110
230
8.05
0.08
7
0.36
9
0.73
0
2.58
6
0.171
0.320
1110
230
9.22
0.08
7
0.36
9
0.73
0
2.58
6
0.171
0.320
1110
230
8.05
0.08
7
0.36
9
0.73
0
2.58
6
0.171
0.320
1110
230
2.3
0.08
7
0.36
9
0.73
0
2.58
6
0.171
0.320
1110
230
2.3
0.08
7
0.36
9
0.73
0
2.58
6
0.171
0.320
1110
230
2.3
0.08
7
0.36
9
0.73
0
2.58
6
0.171
0.320
1110
230
2.3
0.08
7
0.36
9
0.73
0
2.58
6
0.171
0.320
Note: A.P. – Alternate plant, Mar – Marriot Plant, Uty - Utility
46
4.2. System Impedances
Tables 4.1 - 4.3 describe equipment ratings and impedances for Marriot power plant,
Alternate power plant, and equivalent Utility system. Impedances were converted on a
common MVA base defined in table 4.4. Unit sub-transient reactances is the positive
sequence impedance to consider the highest rated fault current during the 2-4 cycle
duration of the fault. Negative sequence impedances are considered equal to the positive
sequence impedances to produce conservative fault studies. Unit and transformer zero
sequence impedances will consist of the reactive component as the real portion will not
significantly contribute discrepancies in fault calculations. Recall from the previous
section of station service load specifications are neglected for the manual fault
calculations. These loads will be included for the simulated fault current data to verify
accuracy of the fault studies.
Table 4.4: System Base Values
Base Values
MVA
kV
I
Z
100 MVA
230 kV
251.022 A
529 Ω
47
Table 4.5: Marriot Plant Equipment Impedance Data
Equipment
Unit 1
Unit 2
Unit 3
Marriot Plant Equipment Impedance PU
Positive Sequence
Zero Sequence Impedance
Impedance
Z.subtran_Marr.U1 =
Z.zero_Marr.U1 = 0.1051i
0.0019+0.1908i
Z.subtran_Marr.U2 =
Z.zero_Marr.U2 = 0.14i
0.0019+0.1826i
Z.subtran_Marr.U3 =
Z.zero_Marr.U3 = 0.1051i
0.0016+0.1908i
Unit 4
Z.subtran_Marr.U4 =
0.0019+0.1826i
Z.zero_Marr.U4 = 0.14i
Unit 5
Z.subtran_Marr.U5 =
0.0016+0.1908i
Z.zero_Marr.U5 = 0.1051i
Unit 6
Z.subtran_Marr.U6 =
0.0019+0.1826i
Z.zero_Marr.U6 = 0.14i
Transformer K1A
Z.1_K1A = 0.00280+0.111i
Z.0_K1A = 0.0943i
Transformer K2A
Z.1_K2A = 0.0027+0.1085i
Z.0_K2A = 0.09220i
Transformer K3A
Z.1_K3A = 0.0028+0.1094i
Z.0_K3A = 0.09300i
Transformer K4A
Z.1_K4A = 0.0028+0.1108i
Z.0_K4A = 0.0942i
Transformer K5A
Z.1_K5A = 0.0028+0.1108i
Z.0_K5A = 0.0942i
Transformer K6A
Z.1_K6A = 0.0028+0.111i
Z.0_K6A = 0.0943i
Melanie line 1 Marriot E. Section
to tap 1
Johnson line 2 Marriot Middle
Section to Utility Bus
Z.1_TL.L1.Marr._tap =
0.0013+0.0111i
Z.1_TL.L2.Marr. =
0.00155+0.0127i
Z.0_TL.L1.Marr._tap =
0.0056+0.0394i
Z.0_TL.L2.Marr. =
0.00644+0.0451i
Bell line 3 Marriot W. Section to
tap 3
Z.1_TL.L3.Marr._tap =
0.0013+0.0111i
Z.0_TL.L3.Marr._tap =
0.0056+0.0394i
48
Table 4.6: Alternate Plant Equipment Impedance Data
Equipment
Unit 1
Alternate Plant Equipment Impedances PU
Positive Sequence
Zero Sequence
Z.subtran_Alt._Plt.U1 = 0.018+0.9555i Z.zero_Alt._Plt.U1 = 0.6689i
Unit 2
Z.subtran_Alt._Plt.U2 = 0.0213+1.073i
Z.zero_Alt._Plt.U2 = 0.6439i
Unit 3
Z.zero_Alt._Plt.U3 = 0.6439i
Alternate Trf. 1
Z.subtran_Alt._Plt.U3 =
0.0213+1.073i
Z.subtran_Alt._Plt.U4 =
0.0213+1.073i
Z.1_Alt.Trf.1 = 0.0151+0.373i
Alternate Trf. 2
Z.1_Alt.Trf.2 = 0.0169+0.4054i
Z.0_Alt.Trf.2 = 0.3446i
Alternate Trf. 3
Z.1_Alt.Trf.3 = 0.017+0.4095i
Z.0_Alt.Trf.3 = 0.3481i
Alternate Trf. 4
Z.1_Alt.Trf.4 = 0.0169+0.4054i
Z.0_Alt.Trf.4 = 0.3446i
Alternate line 1- tap 1 to Alternate
plant
Z.1_TL1.Alt_Tap =
0.000377+0.0032i
Z.0_TL1.Alt_Tap = 0.0112i
Alternate line 3- tap 3 to Alternate
plant
Z.1_TL3.Alt_Tap =
0.000377+0.0032i
Z.0_TL3.Alt_Tap = 0.0112i
Unit 4
Z.zero_Alt._Plt.U4 = 0.6439i
Z.0_Alt.Trf.1 = 0.3171i
Table 4.7: Utility Equipment Impedance Data
Utility Impedances PU
Equipment
Positive Impedance
Zero Sequence Impedance
Utility impedance
Z.1_Utly = 0.000593+0.0115i
Z.0_Utly = 0.000163+0.0041i
Transmission line utility bus
to tap 1
Z.1_TL.Uty_Tap =
0.00038+0.0031i
Z.0_TL.Uty_Tap =
0.00161+0.0113i
Transmission line utility bus
to tap 3
Z.1_TL.Uty_Tap =
0.00038+0.0031i
Z.0_TL.Uty_Tap =
0.00161+0.0113i
4.3 Sample 3-Phase Fault Study
Perform a study to calculate the flow of positive sequence 3-phase symmetrical fault
current through Melanie line 1, Johnson line 2, and Bell line 3. Alternate line tap 3 is
49
removed from the system, and one Alternate plant transmission line is in-service for
typical operating conditions. Figure 4.1 illustrates the system configuration for this
study.
Marriot Plant:
Transformers: K1A, K2A, K3A, K4A, K5A, K6A
Units: 1 - 6
3
1
6
3-phase
fault
Z.1_K1A
Z.0_K1A
Tap 1
Z.1_TL.Uty_Tap
Z.0_TL.Uty_Tap
Z.1_TL.L1.Marr._tap
Z.0_TL.L1.Marr._tap
Z.1_K2A
Z.0_K2A
4
Z.1_K3A
Z.0_K3A
Z.1_TL.L2.Marr
Z.0_TL.L2.Marr.
Z.1_Utl
Z.1_K4A
Z.0_K4A
y
Z.0_Utly
5
7
Tap 3
Z.1_K5A
Z.0_K5A
Z.1_TL.Uty_Tap
Z.0_TL.Uty_Tap
Z.1_TL.L3.Marr._tap
Z.0_TL.L3.Marr._tap
Z.0_K6A
Z.0_K6A
Z.1_TL3.Alt_Tap
Note: Dashed lines represent out of service equipment.
Z.subtran_Marr.U1
Z.zero_Marr.U1
Z.subtran_Marr.U2
Z.zero_Marr.U2
Z.subtran_Marr.U3
Z.zero_Marr.U3
Z.subtran_Marr.U4
Z.zero_Marr.U4
Z.subtran_Marr.U5
Z.zero_Marr.U5
Z.subtran_Marr.U6
Z.zero_Marr.U6
Z.0_TL3.Alt_Tap
2
Alternate Plant:
Transformers: Trf. 1, Trf. 2, Trf. 3, Trf. 4
Units: 1, 2, 3, 4
Z.1_Alt.Trf.4
Z.0_Alt.Trf.4
Z.1_Alt.Trf.3
Z.0_Alt.Trf.3
Z.1_Alt.Trf.2
Z.0_Alt.Trf.2
Z.1_Alt.Trf.1
Z.0_Alt.Trf.1
Z.subtran_Alt._Plt.U4
Z.subtran_Alt._Plt.U3
Z.subtran_Alt._Plt.U2
Z.subtran_Alt._Plt.U1
Z.zero_Alt._Plt.U4
Z.zero_Alt._Plt.U3
Z.zero_Alt._Plt.U2
Z.zero_Alt._Plt.U1
Legend:
Bus 1 = Marriot East Bus Section
Bus 2 = Alternate Plant Switchyard
Bus 3 = Utility Bus
Bus 4 = Marriot Middle Bus Section
Bus 5 = Marriot West Bus Section
Bus 6 = Line 1 Tap 1
Bus 7 = Line 3 Tap 3
Figure 4.1: Marriot, Alternate Plant, Equivalent Utility Power System
As indicated on figure 4.1, the system orientation is arranged as follows:
•
Alternate plant units 1 – 4 is in service.
•
Marriot plant units 1-6 is in service.
•
Alternate line 1- tap 1 to Alternate plant is in service
•
Alternate line 3- tap 3 to Alternate plant is disconnected
•
3-phase fault on bus 3 (Utility Bus)
The calculated values for 3-phase fault distribution through line sections referenced from
appendix B are provided below:
50
Table 4.8: Mathcad Calculations for 3-Phase Fault Study
1.
Melanie
line 1
Marriot E.
Section bus
to tap 1
fault
current
(current
flow from
bus 1 to 6)
2.
0.155-6.103i
(pu)
Alternate line
1- tap 1 to
Alternate
plant bus
fault current
(current flow
from bus 2 to
6)
3.
0.078-2.678i (pu)
Transmission
line utility bus
to tap 1 fault
current (current
flow from bus
6 to 3)
0.233-8.782i (pu)
4.
Bell line 3
Marriot W.
Section to
tap 3 fault
current
(current
flow from
bus 5 to 7)
5.
Johnson
line 2
Marriot
Middle
Section to
Utility
Bus fault
current
(current
flow from
bus 4 to 3)
0.147-6.205i
(pu)
0.149-6.132i
(pu)
Notice the current from line section between tap 1 and utility bus is approximately the
sum of the currents from columns 1 and 2 in table 4.8 (refer to figure 4.1).
Comparison of fault data between manual calculation and Easypower simulation is
organized in table 4.9 below. Fault study will assist in verifying the apparent impedance
seen from Marriot bus sections (section 4.6) for a 3-phase fault on the Utility bus.
Table 4.9: Easypower and Mathcad Data Comparison – 3-Phase Fault
Method
System Configuration
Tap
Easy
power
Mathcad
sheet
Easy
power
tap 1
on
tap 1
on
tap 1
on
SS
Loads
Fault
Bus
Fault
Type
Alt.
Plant
Units
Mar.
Plant
Units
All
All
units
units
No
on
on
All
All
3
units
units
No
phase
on
on
Percent difference (%) of Current Magnitude
Uty.
bus
Uty.
bus
Utilit
y bus
On
3
phase
3
phase
All units
on
All
units
on
Fault Current Distribution (in pu)
Tap 1
Tap
Line
Bell
line
to Alt.
Line
3
Melanie
John3 to
Alt.
plant
Line 1 to to tap
son
Tap
plant
Tap 1
1
Line 2 3
0
0.149-5.8i
0.0762.6i
0.1465.9i
0.1505.8i
0.1556.103i
0.0782.678i
0.1476.205i
0.1496.132i
5.09
2.955
5.038
5.563
0
-0
0.152-5.8i
0.0802.6i
0.1465.9i
0.1505.8i
Note: SS = Station Service (No implies “removed”), Uty. = Utility, Alt. = Alternate,
Mar. = Marriot.
51
According to Table 4.9, values compared between Easypower simulation and Mathcad
calculations have a small percent difference (about 5 % difference), and indicates
accurate data between both methods. The last row in table 4.9 is a simulated fault study
including station service loads. There is a slight increase in fault current distribution on
Melanie line 1 to tap, however all other currents remain the same. Fault data gathered
from Easypower simulation will be considered for distance relay zone 1, 2, and 3
settings.
4.4 Sample Single-Line-To-Ground Fault Study
Perform a study to calculate the flow of ground fault current, 3I0, current through Melanie
line 1 and Johnson line 2. All Alternate line taps 1 and 3 is removed from the system to
induce the highest ground fault current, 3I0, through Johnson line 2 during a single-lineto-ground (SLG) fault on the utility bus. Alternate plant units will be out-of-service for
this study, and shown in figure 4.2.
3
1
Z.1_K1A
Z.0_K1A
Tap 1
SLG fault
Z.1_TL.Uty_Tap
Z.1_TL.L1.Marr._tap
Z.0_TL.Uty_Tap
Z.0_TL.L1.Marr._tap
Z.1_K2A
Z.0_K2A
2
Z.1_K3A
Z.0_K3A
Z.1_Utl
y
Z.subtran_Marr.U1
Z.zero_Marr.U1
Z.subtran_Marr.U2
Z.zero_Marr.U2
Z.subtran_Marr.U3
Z.zero_Marr.U3
Z.0_Utly
Z.1_TL.L2.Marr
Z.0_TL.L2.Marr.
Note: Dashed lines refer to equipment removed from system.
Z.1_K4A
Z.0_K4A
Z.subtran_Marr.U4
Z.zero_Marr.U4
Legend:
Bus 1 = Marriot East Bus Section
Bus 2 = Marriot Middle Bus Section
Bus 3 = Utility Bus
Fig 4.2: Marriot and Equivalent Utility Power System Subject to SLG Fault Study.
As indicated on figure 4.2, the system orientation is arranged as follows:
•
Alternate plant units 1 – 4 removed from service.
•
Marriot plant units 1-4 is in service.
52
•
Equivalent Utility load is removed from Utility bus.
•
Alternate line 1 and 3 - tap 1 and 3 to Alternate plant is removed
•
SLG fault on bus 3 (Utility bus)
The calculated values for SLG fault referenced from Appendix A for the following
transmission line sections are provided below:
Table 4.10: Mathcad Calculations for SLG Fault Study
Ground fault
current, 3I0,
through Marriot
Line 1 to tap 1
Ground fault
current, 3I0,
through Johnson
Line 2 to Utility
Bus
0.199-6.15i (pu)
0.185-6.375i (pu)
Table 4.11: Easypower and Mathcad Data Comparison – SLG Fault
Method
System Configuration
Easy
power
Mathca
d sheet
Tap
lines
All
off
All
off
Easy
power
tap 1
on
SS
Loads
No
No
On
Marriot
Fault Fault
Alt. Plant Plant
Bus
Type
Units
Units
Uty.
All units
Units 1-4
bus
SLG
off
on
Uty.
All units
Units 1-4
bus
SLG
off
on
Percent difference (%) of Current Magnitude
Uty.
bus
SLG
All units
off
Units 1-4
on
Fault Current Distribution
(in pu)
3I0
3I0 Current
Current
Melanie Line
Johnson
1 to Tap 1
Line 2
0.253-6.7i
0.199-6.15i
0.285-7.1i
0.1856.375i
8.596
11.384
0.255-6.7i
0.286-7.1i
Note: SS = Station Service (No implies “removed”), Uty. = Utility, Alt. = Alternate,
Mar. = Marriot.
Computed values from the Mathcad calculations show a high percent difference for
Johnson line 2 ground fault current, 3I0. The larger than 10 % differences may be
contributed to a select few neglected resistive components in the zero-sequence Z-bus
53
matrix. The last row in table 4.11 show fault data with station service loads included to
the system; minimal fault current is contributed from this additional load, however should
be considered in fault studies as normal operating conditions. The collected data will be
applied to assist with establishing ground fault settings for the ground overcurrent relays
(instantaneous and time-delay), in addition to the ground carrier start relay. Easypower
simulation data will be considered for the settings for the relays.
4.5 Distance (Mho) Relay Study Zone 1
To restate section 3.3.2 zone 1 setting, the primary protection basis of setting is
independent of in-feed effects from contributing sources, and set to 90% of the shortest
line impedance between the local and remote buses. The line distance is similar between
Marriot buses to Utility bus, and Marriot bus to the Alternate plant bus. Melanie Line 1
and Bell line 3 are the same distance towards their associated taps (1 and 3), and will
have similar zone 1 settings. Johnson Line 2 connects directly to the Utility bus, and is
shorter than the other two respective lines, if including line sections connecting
associated taps to the Utility bus. Melanie Line 1 and Johnson Line 3 Zone 1 setting,
using equation 3.11, 3.12, and 3.13 to define secondary zone 1 setting using line data in
pu.
ZLine1and3
= K ⋅ Zbase ( Z.1_ TL.L1.Marr._ tap + Z.1_ TL.Uty _ Tap )
Zone1
= 0.9 ⋅ 529 ⋅ ( 0.0013 + 0.0111i + 0.00038 + 0.0031i )
=
and,
0.7998+6.7602i (Ω)
(4.1)
54
CTR
PTR
Line1and3
ZLine1and3
⋅
Zone1Secondary = Z Zone1
=
=
0.7998+6.7602i ⋅
1000
5
230000
115 .
(4.2)
0.681 (Ω)
The associated KD-10 relay settings derived from ABB relay manual is: S = 1, T = 0.690,
M=0. To verify the settings is within 1.5% of ZZone1Secondary (equation 3.20),
S ⋅ T 1 ⋅ 0.690
=
1± M
1+0
= 0.690 ≈ 1.35%
1&3
ZZLine
=
1
(4.3)
The relay setting is valid according to ZZ1 and is less than the 1.5% limit.
Procedures for zone 1 setting of Johnson Line 2 are demonstrated in a similar manner:
ZLine2
Zone1 = K ⋅ Zbase ( Z.1_ TL.L2.Marr. )
= 0.9 ⋅ 529 ⋅ ( 0.00155 + 0.0127i )
=
(4.4)
0.7380 + 6.0465i (Ω)
Line2
ZLine2
Zone1Secondary = Z Zone1 ⋅
=
=
CTR
PTR
0.7380 + 6.0465i ⋅
1000
5
230000
115
(4.5)
0.6091 (Ω)
The associated KD-10 relay settings derived from ABB relay manual is: S = 1, T = 0.690,
M=0.12. To verify the settings is within 1.5% of ZZone1Secondary (equation 3.20),
S ⋅ T 1 ⋅ 0.690
=
1± M
1 + .12
= 0.616 ≈ 1.149% .
2
ZZLine
=
1
(4.6)
55
The relay setting is valid according to ZZ1 and is less than the 1.5% limit. A summary of
Mho relay settings is shown in table 4.
4.6 Distance (Mho) Relay Study Zone 2
Fault studies as demonstrated from section 4.4 will apply to establish the largest apparent
impedance seen by Marriot East, Middle, and West Bus sections. Melanie line 1 and
Johnson line 3 has a tap connection linking to Alternate plant. The distance from taps 1 or
3 to Alternate plant is the same distance from tap 1 or 3 to the Utility bus. To determine
the apparent impedance applicable to zone 2 setting, a system configuration that
contributes to the largest apparent impedance (worst case) is considered. The following
table describes the two system configurations for the worst case contingency study.
Table 4.12: Zone 2 Setting System Configurations
Tap
System Configuration
Station
Fault
Service
Locatio
Fault
Load
n
Type
Alternat
e plant
Units
tap 3
off
On
Alt.
plant
3 phase
All
units on
tap 1
off
On
Alt.
plant
3 phase
All
units on
Fault Current Distribution, Iaf (in pu)
Melanie Tap 1 to Bell
Marriot
Line 1
Alt.
Line 3
Tap 3 to
Units
to Tap1
Plant
to tap 3
Alt
Unit 2
off
0.0774.6440.190only.
2.4i
62.3i
3.5i
0
Unit 6
off
0.1900.0754.642only.
3.6i
0 2.4i
62.3i
As described in Table 4.12, all Alternate plant units are in-service for each worst case
condition with a 3-phase fault on the Alternate Plant Bus. The Utility Bus contributes the
most fault current in-feed to the tap, and large currents amount on Alternate line 1-tap 1
to Alternate plant line. The largest apparent impedance seen from Marriot East Bus
Section requires Marriot unit 2 source, and tap 3 removed from service. Similarly,
56
Marriot unit 6 and tap 1 is removed from service for Marriot West Bus Section’s largest
induced apparent impedance.
Equation 3.14 to determine the apparent impedance, ZR, with respect to Marriot East and
West Bus’s is demonstrated below including fault data from table 4.12.
ZLine1
=
R
=
=
fault
3-φ fault
⋅ Z .1_ TL.L1.Marr._ tap + I1_
Zbase ⋅ (I3-.1_φTL.L1.Marr._
TL1.Alt _ Tap ⋅ Z 1_ TL1.Alt _ Tap )
tap
fault
I3-.1_φTL.L1.Marr._
tap
529 ⋅ ( (0.077 − 2.4i) ⋅ (0.0013 + 0.0111i) + (4.644 − 62.3i) ⋅ (0.000377 + 0.0032i) )
(0.077 − 2.4i)
4.207+51.786i (Ω)
(4.7)
and,
Z
Line3
R
=
=
=
fault
3-φ fault
⋅ Z .1_ TL.L3.Marr._ tap + I1_
Zbase ⋅ (I3-.1_φTL.L3.Marr._
TL3.Alt _ Tap ⋅ Z 1_ TL3.Alt _ Tap )
tap
fault
I3-.1_φTL.L3.Marr._
tap
529 ⋅ ( (0.075 − 2.4i) ⋅ (0.0013 + 0.0111i) + (4.642 − 62.3i) ⋅ (0.000377 + 0.0032i) )
(0.075 − 2.4i)
4.172+51.79i (Ω)
(4.8)
respectively. Proceed to Zone 2 setting for Melanie Line 1 and Bell Line 3 with equation
3.15 and shown as,
Line1
ZLine1
=1.20 ⋅ ( 4.207+51.786i )
Zone 2 = 120% ⋅ Z R
=
5.049+62.144i (Ω)
(4.9)
and,
Line3
ZLine3
= 1.20 ⋅ ( 4.172+51.79i )
Zone 2 = 120% ⋅ Z R
=
5.006+62.148i (Ω)
respectively. Or in terms of secondary impedances (equation 3.13)
(4.10)
57
1000
CTR
5
= 5.049+62.144i ⋅
230000
PTR
115
= 6.23484 (Ω)
1
Line1
Zzone2secondary
= Z Line
zone 2 ⋅
(4.11)
and,
1000
CTR
5
= 5.006+62.148i ⋅
230000
PTR
115
= 6.23494 (Ω)
Line1
3
Zzone2secondary
= Z Line
zone 2 ⋅
(4.12)
respectively. To reiterate, determined settings is to account for in-feed which induces the
apparent impedance seen from Marriot Bus Sections. Absence of in-feed sources will
cause zone 2 to overlap primary protections from remote zones of protection. However,
zone 2 activity is coordinated with a time delay and pilot protection.
Zone 2 setting for Johnson Line 2 is defined with equation 3.16, and demonstrated below.
Line 2
ZZone2
= 120% ⋅ Zbase ⋅ (ZZ.1 _ TL.L2.Marr ) = 1.20 ⋅ 529 ⋅ ( 0.00155 + 0.0127i )
=
0.984+8.062i (Ω)
(4.13)
or in terms of secondary impedance (equation 3.13),
Z
Line 2
zone2secondary
1000
CTR
5
⋅
= Z
= 0.984+8.062i ⋅
230000
PTR
115 .
= 0.81218 (Ω)
Line 2
zone 2
(4.14)
In-feed properties are not applied since line taps do not exist on Johnson Line 2. Further
implementation into KD-10 (Model 0.75 – 21.2) relays contains the following tap settings
shown in table 4.13, and applies equation 3.20 to verify calculated secondary impedance
values from above.
58
Table 4.13: KD-10 Zone 2 Tap Settings
S⋅T
1 ± M
Applicable
Line
“ S” autotransformer
primary
“T”
compensator
tap
“ M “ autotransformer
secondary tap
ZSetting(Secondary) =
Percent
from
Secondary
Impedance
Melanie
Line 1
Johnson
Line 2
Bell Line 3
1
5.8
-0.06
6.170
1.04%
1
0.87
0.06
0.821
1.09%
1
5.8
-0.06
6.170
1.04%
All KD-10 settings are valid according to “Percent from Secondary Impedance” column
values from table 4.13, and are all less than 1.5% tolerance. Summary of mho zone 2
relay settings is organized in table 4.16.
4.7 Distance (Mho) Relay Study Zone 3
As mentioned above, the distance from taps 1 or 3 to Alternate plant is the same distance
from tap 1 or 3 to the Utility bus. To determine the apparent impedance applicable to
zone 3 setting, a system configuration that contributes to the largest apparent impedance
(worst case) is considered. The following table describes the three system configurations
for the worst case contingency study for each line.
59
Table 4.14: Zone 3 Setting System Configurations
System Configuration
Station
Service
Tap
tap 1
off
Fault Current Distribution, Iaf (in pu)
Load
Fault
Location
Fault
Type
Alternate plant
Units
Marriot
Units
On
K1A
3
phase
All units on
All units
on
System Configuration
Station
Service
Tap
tap 1
off
Load
Fault
Type
Alternate plant
Units
Marriot
Units
On
K3A
3
phase
All units on
All units
on
System Configuration
Tap
tap 3
off
Marriot to
K1A.
3.835-40.5i
3.902-43.7i
Line
1
Fault Current Distribution, Iaf (in pu)
Fault
Location
Station
Service
Tap to Marriot
Line 1
Tap to Marriot
Line 1
Marriot to
K1A.
4.750-42.5i
4.879-45.7i
Line
2
Fault Current Distribution, Iaf (in pu)
Load
Fault
Location
Fault
Type
Alternate plant
Units
Marriot
Units
On
K6A
3
phase
All units on
Units 2,4,6
off
Tap to Marriot
Line 1
Marriot to
K1A.
4.355-38.9i
4.473-42.0j
Line
3
As described in Table 4.14, all Alternate plant units are in-service for each worst case
condition with a 3-phase fault on K1A, K2A, and K3A respectively. The Utility Bus
contributes the most fault current in-feed. Equation 3.19 to determine the apparent
impedance, ZR, with respect to each line is demonstrated below including fault data.
Zone 3 Line 1 Settings:
Basis of settings: 120% of Alternate Plant Zone 2 overreach.
Provided from Alternate Plant: Zone 2 is given as 5.04 Ω secondary.
Alternate Plant CT Ratio= 500/5
60
Alternate Plant PT Ratio= 2000/1
PTR
CTR
2000
= 5.04 Ω X 1
500
5
= 100.8 Ω primary
Z2AlternatePlant = 5.04 Ω x
(4.15)
Melanie Line #1 Impedance:
ZMelanie =.001321013+.011028j
=5.87∠83.169ο
Therefore,
Zone 2AlternatePlant - ZA.P.-Marriot =
100.8 Ω - 5.87 Ω =
= 94.93 Ω
(4.16)
According to Schweitzer standard [8],
1.2 × Zone 2remote end overreach =
1.2 × 94.93 Ω =
= 113.92 Ω primary
(4.17)
Marriot Zone 3 setting can be calculated as
CTR
PTR
1000
5
= 113.92 primary Ω X
230, 000
115
= 11.39 Ω secondary
ZRelay = 113.92 primary Ω x
Since
Zθ = desired ohmic reach of the relay in secondary ohms,
(4.18)
61
Z = Zθ = 11.39 Ω secondary
Z is found to be 11.6 which is 102% of the desired value.
S, T and M, are found to be
S=2
T=5.8
M=+.03
To check the correct settings for Z, plug in the values of S, T, and M into
TS
1+M
(2) (5.8)
=
1 + (.03)
Z=
= 11.6 ∠ 263.17
(4.19)
ο
Proceed to Zone 3 setting for Johnson Line 2 is found as
Zone 3 Line 2 Settings:
Basis of settings: 120% of Utility Zone 2 overreach.
Provided from Alternate Plant: Zone 2 is given as
Z2 Utility = 16.15 Ω primary
Johnson Line #2 Impedance:
ZJohnson =.001513+.012717j
=6.77∠83.215ο
Therefore,
Zone 2 Utility - Z Utility-Marriot =
16.15 Ω - 6.77 Ω =
= 9.38 Ω
(4.20)
62
According to Schweitzer standard [8],
1.2 × Zone 2remote end overreach =
1.2 × 9.38 Ω =
= 11.25 Ω primary
(4.21)
Marriot Zone 3 setting can be calculated as
CTR
PTR
1000
5
= 11.25 primary Ω X
230, 000
115
= 1.12 Ω secondary
ZRelay = 11.25 primary Ω x
(4.22)
Since Zθ = desired ohmic reach of the relay in secondary ohms,
Z = Zθ = 1.12 Ω secondary
Z is found to be 1.13 which is 101% of the desired value.
S, T and M, are found to be
S=1
T=1.16
M=+.03
To check the correct settings for Z, plug in the values of S, T, and M into
TS
1+M
(1) (1.16)
=
1 + (.03)
Z=
= 1.13 ∠ 263.22ο
In-feed properties are not applied since line taps do not exist on Johnson Line 2.
(4.23)
63
Proceed to Zone 3 setting for Bell Line 3 is found as
Zone 3 Line 3 Settings:
Basis of settings: 120% of Alternate Plant Zone 2 overreach.
Provided from Alternate Plant: Zone 2 is given as 5.04 Ω secondary.
Alternate Plant CT Ratio= 500/5
Alternate Plant PT Ratio= 2000/1
PTR
CTR
2000
= 5.04 Ω X 1
500
5
= 100.8 Ω primary
Z2AlternatePlant = 5.04 Ω x
(4.24)
Bell Line #3 Impedance:
ZBell =.001321+.011103j
=5.91∠83.218ο
Therefore,
Zone 2AlternatePlant - ZA.P.-Marriot =
100.8 Ω - 5.87 Ω =
= 94.93 Ω
(4.25)
According to Schweitzer standard [8],
1.2 × Zone 2remote end overreach =
1.2 × 94.93 Ω =
= 113.92 Ω primary
Marriot Zone 3 setting can be calculated as
(4.26)
64
CTR
PTR
1000
5
= 113.92 primary Ω X
230, 000
115
= 11.39 Ω secondary
ZRelay = 113.92 primary Ω x
(4.27)
Since Zθ = desired ohmic reach of the relay in secondary ohms,
Zθ = 11.39 Ω secondary
Z = Zθ = 11.39 Ω secondary
Z is found to be 11.3 which is 102% of the desired value.
S, T and M, are found to be
S=2
T=5.8
M=+.03
To check the correct settings for Z, plug in the values of S, T, and M into
TS
1+M
(2) (5.8)
=
1 + (.03)
Z=
(4.28)
= 11.6 ∠ 263.22ο
4.7.1 PRC-023-1
Transmission relay loadability requires transmission owners to follow criteria to
prevent its phase protective relay settings from limiting transmission system loadability
65
while maintaining reliable protection of the Bulk Electric System for all fault conditions.
PRC-023-1 can be calculated as,
Zrelay =
.85VLL
1.5× 3×I rating
(4.29)
Line loading MVA can be computed as,
Line loading MVA = 3 × I rating × VLL
= 3 × 1110 A × 230,000
= 442MVA
(4.30)
The impedance for Melanie Line 1 is found to be,
Melanie Line #1 Impedance:
ZMelanie =.001321013+.011028j
=5.87∠83.169ο
PRC-023-1 equation can be re-written as:
2
.85VLL
Zrelay =
1.5MVA[cos(θ-30° )]
(.85)(230,000) 2
(1.5)(442x106 )[cos(83.169-30° )]
= 113.14 Ω primary
=
(4.31)
To convert to secondary impedance,
CTR
PTR
1000
5
= 113.14 ×
230,000
115
= 11.314 Ω secondary
Secondary Ω = Primary ×
(4.32)
66
In a similar fashion, calculating PRC-023-1 for Line 2, referring back to equation 4.29,
Line loading MVA can be computed as,
Line loading MVA = 3 × I rating × VLL
= 3 × 1110 A × 230,000
= 442MVA
(4.33)
The impedance for Johnson Line 2 is found to be,
Johnson Line #2 Impedance:
ZJohnson =.001513+.012717j
=6.77∠83.215ο
PRC-023-1 equation can be re-written as:
Zrelay =
2
.85VLL
1.5MVA[cos(θ-30° )]
(.85)(230,000) 2
(1.5)(442x106 )[cos(83.215-30° )]
= 113.26 Ω primary
=
(4.34)
To convert to secondary impedance,
CTR
PTR
1000
5
= 113.26 ×
230,000
115
= 11.326 Ω secondary
Secondary Ω = Primary ×
(4.35)
In a similar fashion, calculating PRC-023-1 for our Line 3, referring back to equation
4.29,
Line loading MVA can be computed as,
67
Line loading MVA = 3 × I rating × VLL
= 3 × 1110 A × 230,000
= 442MVA
(4.36)
The impedance for Bell Line 3 is found to be,
Bell Line #3 Impedance:
ZBell =.001321+.011103j
=5.91∠83.218ο
PRC-023-1 equation can be re-written as:
Zrelay =
2
.85VLL
1.5MVA[cos(θ-30° )]
(.85)(230,000) 2
=
(1.5)(442x106 )[cos(83.218-30° )]
= 113.27 Ω primary
(4.37)
To convert to secondary impedance,
CTR
PTR
1000
5
= 113.27 ×
230,000
115
= 11.327 Ω secondary
Secondary Ω = Primary ×
(4.38)
Below shows the comparison of our calculated PRC-023-1 with our Zone 2 settings
Table 4.15 PRC-023-1 Relay Settings
Line 1
Line 2
Line 3
PRC-023-1 (W)
11.314
11.326
11.327
Zone 2 Setting (W)
6.17
0.821
6.17
68
The table above shows that our line settings are in compliance with the criteria of PRC023-1. Transmission owners shall follow criteria to prevent its phase protective relay
settings from limiting transmission system loadability while maintaining reliable
protection of the Bulk Electric System for all fault conditions. The table below shows a
summary of Zones 1, 2, and 3 settings for each specified line.
Table 4.16: Mho Relay Settings
Lines
Zone #1
Zone # 2
Zone # 3(Reverse)
Melanie Line 1 (Ω)
0.690
6.170
11.6
Johnson Line 2 (Ω)
0.616
0.821
1.13
Bell Line 3 (Ω)
0.690
6.170
11.6
Representation of the mho circles for Melanie Line 1, Johnson Line 2, and Bell Line 3
zones 1, 2, 3 protections is shown in figure 4.3 and 4.4 respectively.
69
Figure 4.3: Line 1 and 3 Mho Circle – Zone 1, 2, 3
70
Figure 4.4: Line 2 Mho Circle – Zone 1, 2, 3
4.8 Ground Overcurrent Setting Study
Referencing ground fault studies from section 4.4, the simulated maximum and minimum
single-line-to-ground fault studies is recorded in table 4.17.
71
Table 4.17: SLG Minimum and Maximum Fault Data
System Configuration
Fault Current Distribution (in pu)
Fault
Bus
Alt.
Plant
Units
Mar.
Plant
Units
Melanie
Line 1
to tap 1
3I0
current
Utilit
y
Bus
All
Units
off
Unit 1
on
only
0.0571.8i
Utility load off,
Station Service
on
Utilit
y
Bus
Utilit
y
Bus
All
Units
off
All
Units
off
Unit 3
on
only
Unit 5
on
only
Tap 3
disconnected
Station Service
on.
Tap
1
All
Units
on
All
Units
on
Utility load and
taps 1 and 3
disconnected
Station Service
load on.
Utilit
y
Bus
All
Units
off
Unit 1
– 4 on
only
--
--
Tap 1
disconnected
Station Service
on
Tap
3
All
Units
on
All
Units
on
--
--
Special system
conditions
Utility load off,
tap 1
disconnected
Station Service
on
Utility load off,
tap 1
disconnected
Station Service
on
Melanie
Line 1
to tap 1
I0
current
0.0190.6i
--
--
--
--
0.57211.1i
Johnson
Line 2 to
Utility
bus
3I0
current
Johnson
Line 2
to
Utility
bus
I0
current
Bell Line
3
to tap 3
3I0
current
Bell Line
3
to tap 3
I0 current
--
--
--
--
--
--
0.0621.8i
0.1913.7
0.0210.6i
--
--
--
--
0.2867.1i
0.0681.8i
0.0952.4i
--
--
0.62811.0i
0.0230.6i
--
--
--
--
0.2093.7i
Note: Reference Appendix B for complete fault current data. Alt. = Alternate, Mar. =
Marriot.
Results from table 4.17 show the necessary operating conditions to produce the minimum
(first three rows) and maximum (last three rows) residual ground fault currents, 3I0,
through the transmission system. The instantaneous pickup setting is determined per
section 3.4.2 by analyzing the max SLG fault on tap 1 and 3 for Melanie Line 1 and Bell
Line 3. Instantaneous setting for Johnson Line 2 requires a SLG fault placed on the
72
Utility bus because there is no tap on its line. Applying rows 4 - 6 data from table 4.17,
the instantaneous overcurrent setting in terms of secondary current (equation 3.24) is,
Line1
I Instan.
= 1.2 ⋅ I base ⋅ 3I0max ⋅ 1
CTR
= 1.2 ⋅ 251.022 ⋅ 0.572 − 11.1i ⋅
5
1100
(4.39)
= 12.682 (A)
Line 2
I Instan.
= 1.2 ⋅ I base ⋅ 3I0max ⋅ 1
CTR
= 1.2 ⋅ 251.022 ⋅ 0.286 − 7.1i ⋅
5
1100
(4.40)
= 8.108 (A)
and,
Line 3
I Instan.
= 1.2 ⋅ I base ⋅ 3I0max ⋅ 1
CTR
= 1.2 ⋅ 251.022 ⋅ 0.628 − 11.0i ⋅
5
1100
(4.41)
= 12.572 (A)
respectively.
To the time-overcurrent pickup setting is based on the lowest residual ground fault
current, 3I0, rows 1-3 from table 4.17 is applied in equation 3.25, and demonstrated
below.
Line1
0
1
ITime
O. = I base ⋅ 3I min ⋅
CTR
5
1100
= 2.055 (A) or 452.066 (A) primary.
= 251.022 ⋅ 0.057 − 1.8i ⋅
(4.42)
73
Line 2
0
1
ITime
O. = I base ⋅ 3I min ⋅
CTR
5
1100
= 2.055 (A) or 451.107 (A) primary
= 251.022 ⋅ 0.062 − 1.8i ⋅
(4.43)
and,
Line 3
0
1
ITime
O. = I base ⋅ 3I min ⋅
CTR
5
1100
= 2.055 (A) or 452.162 (A) primary
= 251.022 ⋅ 0.068 − 1.8i ⋅
(4.44)
respectively. Relays can be set according to the settings determined above. Table 4.18
below organizes the calculated pickup settings for Marriot Lines 1, 2, and 3.
Table 4.18: Calculated Ground Instantaneous and Time-Overcurrent
Line Relay
Instantaneous Pickup (A)
Time-Overcurrent Pickup (A)
Melanie Line 1
12.682
2.055
Johnson Line 2
8.108
2.055
Bell Line 3
12.572
2.055
4.8.1 67 Directional Carrier Ground (KRQ) Relay Setting
While this is an application in the pilot protection scheme, the pickup setting involves the
minimum ground fault current, 3I0, to initiate the relay operation. As the primary
protection for primary faults, the minimum SLG fault condition (fault data from table
4.17) will apply to the tap setting. This tap setting should trip instantaneously for zone 1,
90% of internal faults between Marriot bus sections and the Utility bus, and therefore
74
should be set at the lowest setting possible. This relay should restrain from operation for
external faults beyond the Utility bus or Alternate plant. A carrier blocking signal is sent
from the Utility bus or Alternate plant for external fault conditions. According to KRQ
manual leaflet, the instantaneous setting should not be set lower than the remote bus
carrier pickup current to allow the blocking signal to be sent, and allow supervisory
control of the local 67 relay [21]. Provided specifications indicate remote carrier relays
are set at 0.5A, and a reasonable setting of three times this amount will operate the relay
for the minimum fault current obtained from table 4.17. The instantaneous tap of 1.5A
will induce operation of the 67 for ground faults beyond the Utility bus if a carrier signal
is not sensed. Table 4.19 provides the setting the 67 KRQ relay.
Table 4.19: 67 KRQ Relay Setting [21]
Line Relay
Instantaneous Tap (A)
Melanie Line 1
1.5
Johnson Line 2
1.5
Bell Line 3
1.5
4.8.2 67N Directional Ground Overcurrent (IRQ) Relay Setting
Settings for the instantaneous and time-overcurrent units will be established with the
IRQ-9 manual leaflet [22]. The most reasonable tap settings for Melanie Line 1 and Bell
Line 3 instantaneous unit between 4 – 16 amps is 12 A, or between 10 -40 amps is 15 A.
By selecting a tap of 12, this implies the zone of protection for the instantaneous setting
75
is less than zone 2’s 120% protection, 20% beyond Utility bus at the worst case system
configuration. Since the tap is less than the calculated pickup (table 4.18), the sensitivity
is therefore increased. A tap setting of 15 will incur the opposite effects, and potentially
delay the backup protection for the carrier directional ground relay (67). The tap of 12
will be selected to allow tripping for ground fault currents slightly before taps 1 or 3. The
subsequent reasoning will also be applied with Johnson Line 2’s instantaneous setting,
and will select a 9 within the 4-16 amp range. To set the Time-Overcurrent unit, the veryinverse time curve is considered as stated in section 3.4.3. To address the delay issue with
this unit, it is desired to limit the delay of the pickup value to below 2 seconds. Since
additional relay setting specifications regarding coordination with downstream ground
fault relays is not provided (transformer or unit ground overcurrent relaying), 67N time
dial of 1 will be the basis of ground fault coordination with other associated downstream
equipment. Tap settings for the time-overcurrent unit will apply the nearest pickup above
the calculated setting and coordinate with the directional carrier pickup (67). Table 4.20
shows the selected values of the time-overcurrent unit, and the instantaneous unit for each
line relay.
Table 4.20: 67N IRQ Relay Settings
Line Relay
Instantaneous Tap
Time-Overcurrent Tap
Time Dial
Melanie Line 1
12
1.0
1
Johnson Line 2
9
1.0
1
Bell Line 3
12
1.0
1
76
Figure 4.5 is the time-current curve for the very-inverse characteristic time-overcurrent
unit of the IRQ relay for lines 1, 2, and 3.
Min SLG Fault Utility Bus
(approximately 452 A)
Approximately 1.3 sec
(78 cycles) delay for
time-overcurrent unit
pickup setting.
220 (A)
Tap = 1.0
440 (A)
660 (A)
880 (A)
1100 (A)
1320 (A)
1540 (A)
1760 (A)
1980 (A)
2200 (A)
2640 (A)
3080 (A)
3520 (A)
3960 (A)
4400 (A)
Fig 4.5: Very Inverse Time-Overcurrent Curve [22]
According to figure 4.5, a 1.3 second delay is expected for the minimum ground fault
pickup alluded to in table 4.20. This time delay allows coordination with the
instantaneous pickup tap of 1.5A from the directional carrier ground (67). While the
minimum ground fault current does not result in three times the tap value, section 3.4.2,
the coordination between this relay with the primary directional carrier ground (67)
allows this setting.
77
4.9 Directional Comparison Blocking Carrier Logic Scheme
The supervision of the zone 2 mho relay (21Z2), directional carrier ground (67), in
addition to initiating carrier blocking relays (21Z3, 85L) is discussed. Functions and
application of each relay in the directional comparison blocking scheme is described
below.
•
Forward zone 1 mho distance relay (21Z1) operates instantaneously for all
internal three phase and line-to-line faults. No blocking signal is generated from
this relay, nor is this relay carrier supervised.
•
Forward zone 2 mho distance relay (21Z2) will trip instantaneously for external
and internal three phase or line-to-line faults unless a carrier blocking signal from
Alternate plant or Utility bus is received. If carrier is sensed, a delay of 0.3
seconds (18 cycles) will elapse before the carrier is superseded and trips the line
breaker.
•
Reverse zone 3 mho distance relay (21Z3) instantaneously generates a carrier
blocking signal to the remote plant (1-5 cycles) on three phase or line-to-line
faults in the Marriot plant. Zone 3 delays for 0.4 seconds (24 cycles) then trips
associated line breaker if downstream relays fail to clear the fault.
•
Carrier directional ground (67) relay operates instantaneously on low ground
faults (3I0) toward Alternate plant and Utility bus unless blocked by carrier
blocking signal from remote locations.
•
Directional ground overcurrent (67N) relay has two modes of operation: First
mode of operation will be instantaneously for large internal ground faults (3I0)
78
and disrupt the carrier blocking signal from remote buses. Second mode will
consider low ground faults with a time-delay as backup for the 67 relay. No
carrier blocking supervision is applied for this relay.
•
Carrier ground start (85L) relay actuates the carrier blocking signal if the pickup
of 0.5A ground residual current (3I0) is sensed in the reverse direction (towards
Marriot Plant). A delay of 2-16 milli seconds occurs before the signal is
generated.
Alternate
Plant
Utility Load
Trip Marriot
Line
Breaker
OR
21Z1
Forward Zone 1 Distance
Trip Yard Breaker
21Z2
Marriot
Carrier Block
Signal
02
Time Delay = 0.3 sec
Forward Zone 2 Distance
Time Delay IF Carrier Block Signal Sensed;
Else, Instantaneous trip
Transmitter
21Z3
Reverse Zone 3 Distance.
Start Carrier Block Signal
Time Delay
Receiver
Pilot
Communication
System
02
Time Delay = 0.4 sec
AND
67N
Forward Directional Ground Overcurrent.
Instantaneous Pickup at 12A Secondary = Trip Breaker
Time-Overcurrent Pickup at 1A Secondary = 1.3 sec, Trip Breaker
67
Alternate Plant, Utility
Bus Carrier Block Signal
Forward Carrier Directional Ground.
Instantaneous Pickup at 1.5A Secondary = Trip Breaker
Unless Carrier Block Opposes Tripping.
85L
Reverse Carrier Ground Start
@ 0.5 A Secondary = Start Carrier Block Signal
Fig 4.6: Directional Comparison Blocking Carrier Scheme
Figure 4.6 shows a logic diagram to represents the aforementioned details above.
79
CHAPTER 5
CONCLUSION
Protection systems such as relays play an important role in protecting the power system.
In this project we focused on distance and ground overcurrent protection of transmission
lines. A distance relay detects the change in impedance on a line by measuring the
voltage and current flowing through the line. An Overcurrent relay operates or picks up
when its current exceeds a predetermined value. Overcurrent relay would operate as a
backup to the distance relay. Our system involved two sample power plants which fed
power into three-phase transmission line. A total of 10 generator/motor units, 10 power
transformers, 7 transmission line sections, and 1 equivalent utility load were associated to
the sample power system. We were able to determine the proper relay settings for
distance and ground overcurrent relaying on the present system configuration after indepth fault analysis. We provided step distance protection and used a ground overcurrent
relay as backup protection for the sampled power plant. We set distance relay settings for
Zones 1, 2, and 3. Zone 1 was set at 80% while Zone 2 was set at 120%. Zone 2 saw
beyond the utility bus and the Alternate Plant. Zone 3 was a reverse sensing relay. We
also set ground overcurrent relay and a select few of those relays were supervised by
directional comparison blocking scheme. Carrier scheme is a type of differential
protection for which the quantities at the terminals were compared by a communication
channel, rather than by a direct-wire interconnection of the relay input devices. Proper
application and coordination of distance relays and ground over-current relays is vital in a
system requiring reliable electrical service. The expected results gave us line protection
80
for 230 kV transmission lines. We have learned that each power system is unique. Not all
protection schemes are applicable to all power systems. One cannot apply a general
scheme to a specific power system. Typical relay settings do not apply to all application.
With the lack information about other power plant relay settings, we could have achieved
a more reliable relay coordination. After completing this project, we now know more
information about electromechanical relays even though most are not being used
nowadays. The important key is we know the fundamentals on how to set distance and
ground overcurrent relays.
81
APPENDIX A
MATHCAD SHEET FAULT STUDY
Mathcad 3-Phase Fault Study
The sub-transient reactance will be taken as the positive sequence reactance to account
for the highest fault current possible, and to typically consider safety for equipment
design (Gonen, pp. 462)(Std. 399-1997 pp. 194). The transient reactance is considered
in fault studies mainly for relay settings, and with impedances slightly larger than the
sub-transient values, fault currents are in turn smaller. The study will begin with redefining the equipment impedances. Refer to chapter 4 for equipment specifications,
and figure 4.1 for system configuration and fault location.
Marriot Plant:
Transformers: K1A, K2A, K3A, K4A, K5A, K6A
Units: 1 - 6
3
1
6
Z.1_K1A
Z.0_K1A
Tap 1
Z.1_TL.Uty_Tap
Z.0_TL.Uty_Tap
3-phase
fault
Z.1_TL.L1.Marr._tap
Z.0_TL.L1.Marr._tap
Z.1_K2A
Z.0_K2A
4
Z.1_K3A
Z.0_K3A
Z.1_TL.L2.Marr
Z.0_TL.L2.Marr.
Z.1_Utl
Z.1_K4A
Z.0_K4A
y
Z.0_Utly
5
7
Tap 3
Z.1_K5A
Z.0_K5A
Z.1_TL.Uty_Tap
Z.0_TL.Uty_Tap
Z.1_TL.L3.Marr._tap
Z.0_TL.L3.Marr._tap
Z.0_K6A
Z.0_K6A
Z.1_TL3.Alt_Tap
Note: Dashed lines represent out of service equipment.
Z.subtran_Marr.U1
Z.zero_Marr.U1
Z.subtran_Marr.U2
Z.zero_Marr.U2
Z.subtran_Marr.U3
Z.zero_Marr.U3
Z.subtran_Marr.U4
Z.zero_Marr.U4
Z.subtran_Marr.U5
Z.zero_Marr.U5
Z.subtran_Marr.U6
Z.zero_Marr.U6
Z.0_TL3.Alt_Tap
2
Alternate Plant:
Transformers: Trf. 1, Trf. 2, Trf. 3, Trf. 4
Units: 1, 2, 3, 4
Z.1_Alt.Trf.4
Z.0_Alt.Trf.4
Z.1_Alt.Trf.3
Z.0_Alt.Trf.3
Z.1_Alt.Trf.2
Z.0_Alt.Trf.2
Z.1_Alt.Trf.1
Z.0_Alt.Trf.1
Z.subtran_Alt._Plt.U4
Z.subtran_Alt._Plt.U3
Z.subtran_Alt._Plt.U2
Z.subtran_Alt._Plt.U1
Z.zero_Alt._Plt.U4
Z.zero_Alt._Plt.U3
Z.zero_Alt._Plt.U2
Z.zero_Alt._Plt.U1
Legend:
Bus 1 = Marriot East Bus Section
Bus 2 = Alternate Plant Switchyard
Bus 3 = Utility Bus
Bus 4 = Marriot Middle Bus Section
Bus 5 = Marriot West Bus Section
Bus 6 = Line 1 Tap 1
Bus 7 = Line 3 Tap 3
Fig 4.1: Marriot, Alternate Plant, Equivalent Utility Power System.
82
Step 1: Define impedances to new PU values
Base voltage on transmission
line side (Line to line value)
Vb :=
230 × 10
Base apparent power
S b :=
100 × 10
Base current
Ib :=
Sb
=
3
v
6
va
251.022
A
3 Vb
2
Base impedance
Vb
=
Zbase :=
Sb
529
W
All impedances are reflecting on a common MVA base.
Alternate Plant equipment ratings (New PU values)
Positive (sub-transient)
and zero sequence
impedances of Alternate
plant
generating/pumping
units 1 - 4.
Transformer positive
and zero
sequence impedances
of Alternate plant
transformers
1 - 4.
Zsubtran_Alt._Plt.U1 := 0.018 + 0.9555i
Zzero_Alt._Plt.U1 := 0.6689i
Zsubtran_Alt._Plt.U2 := 0.0213 + 1.073i
Zzero_Alt._Plt.U2 := 0.6439i
Zsubtran_Alt._Plt.U3 := 0.0213 + 1.073i
Zzero_Alt._Plt.U3 := 0.6439i
Zsubtran_Alt._Plt.U4 := 0.0213 + 1.073i
Zzero_Alt._Plt.U4 := 0.6439i
Z1_Alt.Trf.1 := 0.0151 + 0.373i
Z0_Alt.Trf.1 := 0.3171i
Z1_Alt.Trf.2 := 0.0169 + 0.4054i
Z0_Alt.Trf.2 := 0.3446i
Z1_Alt.Trf.3 := 0.017 + 0.4095i
Z0_Alt.Trf.3 := 0.3481i
Z1_Alt.Trf.4 := 0.0169 + 0.4054i
Z0_Alt.Trf.4 := 0.3446i
83
Marriot Plant equipment (New PU values):
Marriot plant
generator/motor positive
(sub-transient) and zero
sequence impedances
for units 1 - 6.
Marriot plant
transformer positive
(sub-transient) and zero
sequence impedances
K1A - K6A.
Zsubtran_Marr.U1 := 0.0019 + 0.1908i
Zzero_Marr.U1 := 0.1051i
Zsubtran_Marr.U2 := 0.0019 + 0.1826i
Zzero_Marr.U2 := 0.14i
Zsubtran_Marr.U3 := 0.0016 + 0.1908i
Zzero_Marr.U3 := 0.1051i
Zsubtran_Marr.U4 := 0.0019 + 0.1826i
Zzero_Marr.U4 := 0.14i
Zsubtran_Marr.U5 := 0.0016 + 0.1908i
Zzero_Marr.U5 := 0.1051i
Zsubtran_Marr.U6 := 0.0019 + 0.1826i
Zzero_Marr.U6 := 0.14i
Z1_K1A :=
Z0_K1A := 0.0943i
0.00280 + 0.111i
Z1_K2A := 0.0027 + 0.1085i
Z0_K2A :=
0.09220i
Z1_K3A := 0.0028 + 0.1094i
Z0_K3A :=
0.09300i
Z1_K4A := 0.0028 + 0.1108i
Z0_K4A := 0.0942i
Z1_K5A := 0.0028 + 0.1108i
Z0_K5A := 0.0942i
Z1_K6A := 0.0028 + 0.111i
Z0_K6A := 0.0943i
Transmission Line impedances (New PU values):
Line impedances Melanie line 1 to tap 1, Johnson line 2 to Utility bus, and Bell
line 3 to tap 3.
Z1_TL.L1.Marr._tap := 0.0013 + 0.0111i
Z1_TL.L2.Marr. := 0.0014 + 0.0114i + 0.000151 + 0.0013i
Z1_TL.L3.Marr._tap := 0.0013 + 0.0111i
Z0_TL.L1.Marr._tap := 0.0056 + 0.0394i
Z0_TL.L2.Marr. := 0.000643 + 0.0045i + 0.0058 + 0.0406i
Z0_TL.L3.Marr._tap := 0.0056 + 0.0394i
84
Line impedance UtilityZ1_TL.Uty_Tap := 0.000208 + 0.0017i + 0.00017 + 0.0014i = 0.00038 + 0.0031i
bus to tap 1 or 3.
Z0_TL.Uty_Tap := 0.000883 + 0.0062i + 0.000722 + 0.0051i =
Line impedance
Alternate line 1 and 3
positive and zero
sequence impedances.
Equivalent Utility positive
and zero sequence
impedance.
0.00161 + 0.0113i
Z1_TL3.Alt_Tap := 0.000377 + 0.0032i
Z0_TL3.Alt_Tap := 0.0112i
Z1_TL1.Alt_Tap := 0.000377 + 0.0032i
Z0_TL1.Alt_Tap := 0.0112i
Z0_Utly := 0.000163 + 0.0041i
Z1_Utly := 0.000593 + 0.0115i
Step 2: Construct Z-bus Matrix
This fault study positive sequence impedance for transformers, lines, and utility
equal the negative sequence impedances to represent the highest fault current
possible.
The system configuration is represented in figure 4.1, comprising of 4
alternate plant units (U1, U2, U3, U4) and 6 Marriot units (U1 - U6) inservice. Alternate line 1 is connected to tap 1 and declared in-service.
Alternate line 3 is disconnected from the system through an associated line
circuit breaker. Station service loads for each plant is disabled to simplify the
fault study.
Considering a 3-phase fault instance, the positive sequence impedances is
considered for analysis. Equivalent impedances for bus 1 , 2, 3, 4, and 5 from
figure 4.1 will form the diagonal elements of the Z-bus matrix by apply rule
1, equation 3.1.
Z11 :=
Z22 :=

1
Z
 subtran_Marr.U1
+ Z1_K1A
1

Z
+ Z1_Alt.Trf.4
subtran_Alt._Plt.U4

+
+
1
Zsubtran_Marr.U2


+ Z1_K2A 
1
Zsubtran_Alt._Plt.U3 + Z1_Alt.Trf.3
+
−1
1
Zsubtran_Alt._Plt.U2 + Z1_Alt.Trf.2
+


Zsubtran_Alt._Plt.U1 + Z1_Alt.Trf.1 
1
−1
85
Z33 := Z1_Utly
Z44 :=

1
Z
subtran_Marr.U3

Z55 :=

1
Z
 subtran_Marr.U5
+ Z1_K3A
+ Z1_K5A
+
+
1
Zsubtran_Marr.U4
1
Zsubtran_Marr.U6
Applying rule 1, equation 3.1 with
the equivalent impedances above:
:


+ Z1_K4A 


+ Z1_K6A 
−1
−1
Z1bus :=
 Z11

 0

 0

 0

 0
0 

0 0 
Z22 0

0 Z33 0 0 

0 0 Z44 0 

0 0 0 Z55 
0
0
0
0
0
0
0
 0.002 + 0.148i



0.009 + 0.36i
0
0
0
0




Z1bus =
0.001 + 0.012i
0
0
0
0




0.002 + 0.148i
0
0
0
0


0.002 + 0.149i 
0
0
0
0

Introduce bus 6 from figure 4.2 by using rule 2, equation 3.2, to connect Marriot E.
Section bus to tap 1 between bus 1 and bus 6:
Z2bus :=
Z1
 bus0 , 0
 Z1
 bus1 , 0

 Z1bus2 , 0

 Z1bus3 , 0

 Z1bus4 , 0

 Z1bus0 , 0

Z1bus
0, 1
Z1bus
0, 2
Z1bus
Z1
0 , 3 bus0 , 4
Z1bus
1, 1
Z1bus
1, 2
Z1
Z1bus
1 , 3 bus1 , 4
Z1bus
2, 1
Z1bus
2, 2
Z1
Z1bus
2 , 3 bus2 , 4
Z1bus
3, 1
Z1bus
3, 2
Z1
Z1bus
3 , 3 bus3 , 4
Z1bus
4, 1
Z1bus
4, 2
Z1
Z1bus
4 , 3 bus4 , 4
Z1bus
0, 1
Z1bus
0, 2
Z1
Z1bus
0 , 3 bus0 , 4


Z1bus

1, 0

Z1bus

2, 0

Z1bus

3, 0

Z1bus

4, 0

Z1bus
+ Z1_TL.L1.Marr._tap 
0, 0

Z1bus
0, 0
86
Introduce bus 7 using rule 2 to connect Bell line 3 Marriot W. Section to tap 3
between bus 5 and bus 7:
Z3bus :=
 Z2bus0 , 0
 Z2
 bus1 , 0

 Z2bus2 , 0

 Z2bus3 , 0

 Z2bus4 , 0

 Z2bus5 , 0

 Z2
 bus4 , 0
Z2bus
0, 1
Z2bus
0, 2
Z2bus
0, 3
Z2bus
0, 4
Z2bus
0, 5
Z2bus
1, 1
Z2bus
1, 2
Z2bus
1, 3
Z2bus
1, 4
Z2bus
1, 5
Z2bus
2, 1
Z2bus
2, 2
Z2bus
2, 3
Z2bus
2, 4
Z2bus
2, 5
Z2bus
3, 1
Z2bus
3, 2
Z2bus
3, 3
Z2bus
3, 4
Z2bus
3, 5
Z2bus
4, 1
Z2bus
4, 2
Z2bus
4, 3
Z2bus
4, 4
Z2bus
4, 5
Z2bus
5, 1
Z2bus
5, 2
Z2bus
5, 3
Z2bus
5, 4
Z2bus
5, 5
Z2bus
4, 1
Z2bus
4, 2
Z2bus
4, 3
Z2bus
4, 4
Z2bus
4, 5


Z2bus

1, 4

Z2bus

2, 4

Z2bus

3, 4

Z2bus

4, 4

Z2bus

5, 4

Z2bus
+ Z1_TL.L3.Marr._tap 
4, 4

Z2bus
0, 4
All buses are included, and branch impedances connecting existing buses
remain. Applying rule 3, equation 3.3 - 3.5 to include Transmission line utility
bus to tap 3 between bus 3 and 7:
−
+ Z3bus
Z48 := Z1_TL.Uty_Tap + Z3bus
6, 6
2, 2
2 ⋅Z3bus
2, 6
T
Z4bus := Z3bus −
 Z3bus0 , 6 − Z3bus0 , 2   Z3bus0 , 6 − Z3bus0 , 2 
 Z3
  Z3

− Z3bus
− Z3bus
 bus1 , 6
1 , 2   bus1 , 6
1, 2 



 Z3bus2 , 6 − Z3bus2 , 2   Z3bus2 , 6 − Z3bus2 , 2 



 Z3bus3 , 6 − Z3bus3 , 2  ⋅ Z3bus3 , 6 − Z3bus3 , 2 



 Z3bus4 , 6 − Z3bus4 , 2   Z3bus4 , 6 − Z3bus4 , 2 



 Z3bus5 , 6 − Z3bus5 , 2   Z3bus5 , 6 − Z3bus5 , 2 



 Z3bus6 , 6 − Z3bus6 , 2   Z3bus6 , 6 − Z3bus6 , 2 



Z48
Including branch Johnson line 2 Marriot Middle Section to Utility Bus
connecting bus 3 to 4 using rule 3:
−
+ Z4bus
Z58 := Z1_TL.L2.Marr. + Z4bus
2, 2
3, 3
2 ⋅Z4bus
2, 3
87
T
Z5bus := Z4bus −
 Z4bus0 , 3 − Z4bus0 , 2   Z4bus0 , 3 − Z4bus0 , 2 
 Z4
  Z4

− Z4bus
− Z4bus
 bus1 , 3
1 , 2   bus1 , 3
1, 2 



 Z4bus2 , 3 − Z4bus2 , 2   Z4bus2 , 3 − Z4bus2 , 2 



 Z4bus3 , 3 − Z4bus3 , 2  ⋅ Z4bus3 , 3 − Z4bus3 , 2 



 Z4bus4 , 3 − Z4bus4 , 2   Z4bus4 , 3 − Z4bus4 , 2 



 Z4bus5 , 3 − Z4bus5 , 2   Z4bus5 , 3 − Z4bus5 , 2 



 Z4bus6 , 3 − Z4bus6 , 2   Z4bus6 , 3 − Z4bus6 , 2 



Z58
Including branch Transmission line utility bus to tap 1 connecting bus 3 to 6
using rule 3:
−
+ Z5bus
Z68 := Z1_TL.Uty_Tap + Z5bus
5, 5
2, 2
2 ⋅Z5bus
2, 5
T
Z6bus := Z5bus −
Z5
− Z5bus
− Z5bus
Z5
0 , 2   bus0 , 5
 bus0 , 5
0 , 2 

 Z5


− Z5bus
Z5
− Z5bus
 bus1 , 5
1 , 2   bus1 , 5
1, 2 



 Z5bus2 , 5 − Z5bus2 , 2   Z5bus2 , 5 − Z5bus2 , 2 



 Z5bus3 , 5 − Z5bus3 , 2  ⋅ Z5bus3 , 5 − Z5bus3 , 2 



 Z5bus4 , 5 − Z5bus4 , 2   Z5bus4 , 5 − Z5bus4 , 2 



 Z5bus5 , 5 − Z5bus5 , 2   Z5bus5 , 5 − Z5bus5 , 2 



 Z5bus6 , 5 − Z5bus6 , 2   Z5bus6 , 5 − Z5bus6 , 2 



Z68
Including branch "Alternate line 1- tap 1 to Alternate plant bus" connecting bus
2 to 6 using rule 3:
−
+ Z6bus
Z78 := Z1_TL1.Alt_Tap + Z6bus
5, 5
1, 1
2 ⋅Z6bus
1, 5
88
T
Z7bus := Z6bus −
 Z6bus0 , 5 − Z6bus0 , 1   Z6bus0 , 5 − Z6bus0 , 1 
 Z6
  Z6

− Z6bus
− Z6bus
 bus1 , 5
1 , 1   bus1 , 5
1, 1 



 Z6bus2 , 5 − Z6bus2 , 1   Z6bus2 , 5 − Z6bus2 , 1 



 Z6bus3 , 5 − Z6bus3 , 1  ⋅ Z6bus3 , 5 − Z6bus3 , 1 



 Z6bus4 , 5 − Z6bus4 , 1   Z6bus4 , 5 − Z6bus4 , 1 



 Z6bus5 , 5 − Z6bus5 , 1   Z6bus5 , 5 − Z6bus5 , 1 



 Z6bus6 , 5 − Z6bus6 , 1   Z6bus6 , 5 − Z6bus6 , 1 



Z78
0 + 0.008i 0.001 + 0.011i 0 + 0.008i 
 0.002 + 0.021i 0.001 + 0.011i 0 + 0.008i 0 + 0.008i


0.001
0.011i
+
0.001
+
0.015i
0
+
0.009i
0
+
0.008i
0
+ 0.008i
0.001 + 0.012i 0 + 0.009i 

 0 + 0.008i
0 + 0.009i 0 + 0.009i 0 + 0.009i
0 + 0.008i
0 + 0.009i
0 + 0.009i 


Z7bus =  0 + 0.008i
0 + 0.008i 0 + 0.009i 0.002 + 0.02i 0 + 0.008i
0 + 0.008i
0 + 0.008i 


0 + 0.008i 0 + 0.008i 0 + 0.008i 0.002 + 0.021i 0 + 0.008i 0.001 + 0.011i 
 0 + 0.008i
 0.001 + 0.011i 0.001 + 0.012i 0 + 0.009i 0 + 0.008i
0 + 0.008i 0.001 + 0.012i 0 + 0.009i 


0 + 0.009i 0 + 0.009i 0 + 0.008i 0.001 + 0.011i 0 + 0.009i 0.001 + 0.012i 
 0 + 0.008i
Step 3: Fault Calculations
Calculating a 3-phase fault on bus 3 (Utility bus) is completed by using Z-bus
matrix element on row 3, column 3; this is the system equivalent impedance
referenced from bus 3. Mathcad executes matrix calculations by assigning the
first element with 0 row, 0 column. Therefore element Z3,3 is represented as,
Z2,2.
Prefault voltage at bus 3:
Vf :=
Equation 3.6, 3-phase fault
at bus 3 (Utility bus):
Vf
=
Ia1 :=
Z7bus
2, 2
1
pu
5.001 − 107.844i
pu
89
Equation 3.8 to determine the bus voltages during the 3-phase fault:
V1 :=
1 − Z7bus
⋅I = 0.095 − 0.009i
0 , 2 a1
pu
V2 :=
1 − Z7bus
⋅I = 0.036 − 0.003i
1 , 2 a1
pu
V3 :=
1 − Z7bus
V4 :=
1 − Z7bus
⋅I = 0
2 , 2 a1
pu
⋅I = 0.079 − 0.008i
3 , 2 a1
V5 :=
1 − Z7bus
⋅I = 0.087 − 0.008i
4 , 2 a1
pu
V6 :=
1 − Z7bus
⋅I = 0.027 − 0.003i
5 , 2 a1
pu
V7 :=
1 − Z7bus
⋅I = 0.019 − 0.002i
6 , 2 a1
pu
pu
Equation 3.9 to determine fault currents through associated line sections:
Melanie line 1 Marriot E. Section bus
to tap 1 fault current (current flow I.16 :=
from bus 1 to 6):
Alternate line 1- tap 1 to Alternate
plant bus fault current (current flow
from bus 2 to 6):
V1 − V6
Z1_TL.L1.Marr._tap
V2 − V6
I26 :=
=
Z1_TL1.Alt_Tap
=
0.155 − 6.103i
0.078 − 2.678i
Transmission line utility bus to tap 1
fault current (current flow from bus 6
to 3):
V6 − V3
I63 :=
=
Z1_TL.Uty_Tap
0.233 − 8.782i
Johnson line 2 Marriot Middle
Section to Utility Bus fault current
(current flow from bus 4 to 3):
V4 − V3
I43 :=
=
Z1_TL.L2.Marr.
0.147 − 6.205i
pu
pu
pu
pu
90
Bell line 3 Marriot W. Section to tap
3 fault current (current flow from bus
5 to 7):
V5 − V7
I57 :=
=
Z1_TL.L3.Marr._tap
0.149 − 6.132i
pu
Compare calculated fault currents with Easypower simulated data.
Mathcad Single-Line-to-Ground
Fault Study
From subsequent analysis, positive and negative sequence impedances are equal to
determine the highest fault current through the system. SLG fault studies assists
with ground fault protection criterions such as overcurrent, instantaneous, and
carrier start settings. Refer to figure 4.2 for system configuration and fault
location.
3
1
Z.1_K1A
Z.0_K1A
Tap 1
SLG fault
Z.1_TL.Uty_Tap
Z.1_TL.L1.Marr._tap
Z.0_TL.Uty_Tap
Z.0_TL.L1.Marr._tap
Z.1_K2A
Z.0_K2A
2
Z.1_K3A
Z.0_K3A
Z.1_Utl
y
Z.subtran_Marr.U1
Z.zero_Marr.U1
Z.subtran_Marr.U2
Z.zero_Marr.U2
Z.subtran_Marr.U3
Z.zero_Marr.U3
Z.0_Utly
Z.1_TL.L2.Marr
Z.0_TL.L2.Marr.
Note: Dashed lines refer to equipment removed from system.
Z.1_K4A
Z.0_K4A
Legend:
Bus 1 = Marriot East Bus Section
Bus 2 = Marriot Middle Bus Section
Bus 3 = Utility Bus
Fig 4.2: Marriot and Equivalent Utility Power System subject to SLG fault study.
Step 1: Define impedances to new PU values
Marriot : equipment ratings (New PU values)
Previously defined above.
Z.subtran_Marr.U4
Z.zero_Marr.U4
91
Step 2: Forming Positive and Zero Sequence Z-bus Matrix
Alternate plant is disconnected from line taps 1 and 3, and Marriot units 1 - 4 is
connected. Station service loads for each plant is disabled to simplify the fault
study.
Develop the positive sequence Z-bus matrix:
Apply rule 1, equation 3.1 to define diagonal elements of the positive sequence
Z-bus matrix.
Equivalent positive
sequence impedances at
Marriot East Bus Section
(Bus 1):
Z 11 :=
Equivalent impedances at
Marriot Middle Bus Section
(Bus 2):
Z 1bus :=
 Z 11

 0

Z 44 :=
1
1


+
Z

 subtran_M arr.U1 + Z 1_K1A Z subtran_M arr.U2 + Z 1_K2A 
−1
1
1


+
Z
+ Z 1_K3A
Z subtran_M arr.U4 + Z 1_K4A 
subtran_M
arr.U3




Z 44 

0
Including bus 3 (Utility Bus) and connecting line sections, Melanie line 1
Marriot E. Section to tap 1 and Transmission line utility bus to tap 1, to bus 1
(Marriot East Bus Section) using rule 2, equation 3.2: Z13
Z 2bus :=
 Z 1bus
0, 0

 Z 1bus1 , 0

 Z 1bus0 , 0

Z 1bus
Z 1bus
Z 1bus
0, 1
1, 1
0, 1


Z 1bus

1, 0

Z 1bus
+ Z 1_TL.L1.M arr._tap + Z 1_TL.Uty_Tap 
0, 0

Z 1bus
0, 0
Adding branch connection (Johnson line 2 Marriot Middle Section to Utility
Bus) between bus 3 (Utility bus) and 4 (Marriot Middle Bus Section) applying
rule 3, equation 3.3: Z23
−1
92
Z 34 := Z 1_TL.L2.M arr. + Z 2bus
+ Z 2bus
− 2⋅ Z 2bus
1, 1
2, 2
1, 2
T
−Z
Z
−Z
Z
 2bus0 , 2 2bus0 , 1   2bus0 , 2 2bus0 , 1 



 Z 2bus1 , 2 − Z 2bus1 , 1  ⋅  Z 2bus1 , 2 − Z 2bus1 , 1 



 Z 2bus2 , 2 − Z 2bus2 , 1   Z 2bus2 , 2 − Z 2bus2 , 1 



Z 3bus := Z 2bus −
Z
34
Forming the Zero Sequence Impedance Matrix Z0:
Applying rule 1 to define diagonal elements for zero sequence Z-bus matrix:
Equivalent zero sequence
impedances for Marriot East
Bus Section:
Equivalent zero sequence
impedances for Marriot Middle
Bus Section:
Z 01bus :=
 Z 110

 0

Z 110 :=
Z 440 :=
1
1


+
Z
Z zero_M arr.U2 + Z 0_K2A 
+ Z 0_K1A
zero_M
arr.U1


−1
1
1


+
Z
+ Z 0_K3A
Z zero_M arr.U4 + Z 0_K4A 
zero_M
arr.U3




Z 440 

0
Including bus 3 (Utility Bus) and connecting line sections, "Melanie line 1
Marriot E. Section to tap 1" and "Transmission line utility bus to tap 1", to
bus 1 (Marriot East Bus Section) using rule 2, equation 3.2: Z013 zero
sequence impedances
−1
93
Z 02bus :=
 Z 01bus
0, 0

 Z 01bus1 , 0

 Z 01bus0 , 0

Z 01bus
Z 01bus
Z 01bus
0, 1
1, 1
0, 1


Z 01bus

1, 0

Z 01bus
+ Z 0_TL.Uty_Tap + Z 0_TL.L1.M arr._tap 
0, 0

Z 01bus
0, 0
Adding branch connection (Johnson line 2 Marriot Middle Section to Utility
Bus) between bus 3 (Utility bus) and 4 (Marriot Middle Bus Section)
applying rule 3: Z23 zero sequence impedance.
Z 034 := Z 0_TL.L2.M arr. + Z 02bus
+ Z 02bus
− 2⋅ Z 02bus
1, 1
2, 2
1, 2
T
 Z 02bus − Z 02bus   Z 02bus − Z 02bus 
0, 2
0, 1
0, 1
0, 2



 Z 02bus1 , 2 − Z 02bus1 , 1  ⋅  Z 02bus1 , 2 − Z 02bus1 , 1 



 Z 02bus2 , 2 − Z 02bus2 , 1   Z 02bus2 , 2 − Z 02bus2 , 1 



Z 03bus := Z 02bus −
Z
034
Step 3: Fault Calculations
SLG Fault on Utility bus 3
Pre-fault voltage at bus 3
Vf := 1
Equation 3.7 single-line-to-ground
fault on bus 3 (Utility Bus) assuming
equal positive and negative sequence
impedances:
pu
I012f :=
Vf
2Z
3bus2 , 2 + Z 03bus2 , 2
= 0.128 − 4.175i
pu
94
Sequence Bus Voltages during SLG fault on bus 3:
Equation 3.8, sequence
Bus 1 voltage
during fault on bus 3:
Equation 3.8, sequence
Bus 2 voltage
during fault on bus 3:
Equation 3.8, sequence
Bus 3 voltage
during fault on bus 3:
V01 :=
 0 − Z 03bus ⋅ I012f 
0, 2


 1 − Z 3bus0 , 2⋅ I012f 


 0 − Z 3bus0 , 2⋅ I012f 


V01 =
 −0.22 − 0.007i 
 0.692 − 0.005i 


 −0.308 − 0.005i 
pu
V02 :=
 0 − Z 03bus ⋅ I012f 
1, 2


 1 − Z 3bus1 , 2⋅ I012f 


 0 − Z 3bus1 , 2⋅ I012f 


 −0.228 − 0.007i 


V02 = 0.689 − 0.005i


 −0.311 − 0.005i 
pu
V03 :=
 0 − Z 03bus ⋅ I012f 
2, 2


 1 − Z 3bus2 , 2⋅ I012f 


 0 − Z 3bus2 , 2⋅ I012f 


V03 =
 −0.324 + 0.004i 
 0.662 − 0.002i 


 −0.338 − 0.002i 
pu
Sequence fault current distribution:
Equation 3.9, sequence
fault current through
Melanie line 1 Marriot E.
Section to tap 1:
− V03
V01

0, 0
0, 0
Z
+ Z 0_TL.Uty_Tap
 0_TL.L1.M arr._tap

− V03
V01
1, 0
1, 0
I01213 := 
Z
+
Z
1_TL.Uty_Tap
 1_TL.L1.M arr._tap

− V03
V01
2, 0
2, 0

 Z 1_TL.L1.M arr._tap + Z 1_TL.Uty_Tap












95
Equation 3.9, sequence
fault current through
Johnson line 2 Marriot
Middle Section to Utility
Bus:
 V02 − V03 
0, 0
0, 0
Z

 0_TL.L2.M arr. 
V

021 , 0 − V031 , 0 

I01223 :=
Z

 1_TL.L2.M arr. 
 V02 − V03 
2, 0
2, 0 

 Z 1_TL.L2.M arr. 


Ground fault current, 3I0 branch currents through Marriot Lines 1, and 2 (pu):
Equation 3.10, ground fault current
through Marriot Line 1 to tap 1:
i13 := 3⋅ I01213
= 0.199 − 6.15i
0, 0
pu
Equation 3.10, ground fault current through
Johnson Line 2 to Utility Bus:
i23 := 3⋅ I01223
= 0.185 − 6.375i
0, 0
pu
Compare fault current calculations with Easypower simulation data.
96
APPENDIX B
EASYPOWER FAULT DATA
Table B.1: SLG Fault Study Data
System Configuration
Tap
Tap 3
off
Tap 3
off
Tap 3
off
Tap 1
off
Tap 3
off
SS
Load
Alternate
plant
Units
Marriot
plant
units
Line 1
3I0
Line 1 I0
Line 2
3I0
Line 2
I0
Line 3
3I0
Line 3
I0
SLG
All units
on
All units
on
All units
on
All units
on
All units
on
All units
on
All units
on
All units
on
All units
on
All units
on
0.57211.1i
0.75011.3i
0.4424.4i
0.4294.8i
0.3152.3i
0.1913.7
0.2503.8i
0.1411.5i
0.1431.6i
0.1050.8i
0.3442.5i
0.3892.6i
0.4645.1i
0.4645.1i
0.3522.7i
0.1150.8i
0.1300.9i
0.1151.7i
0.1551.7i
0.1170.9i
.3302.4i
0.3722.4i
0.4494.8i
0.4404.3i
0.63511.8i
0.1100.8i
0.1240.8i
0.1501.6i
0.1471.4i
0.2123.9i
SLG
All units
on
0.5237.1i
0.1742.4i
0.2561.6i
0.0850.5i
0.2451.5i
0.0820.5i
Tap 1
SLG
All units
off
0.56311.6i
0.1883.9i
0.2081.8i
0.0690.6i
0.2051.7i
0.0680.6i
Tap 3
SLG
All units
on
0.1861.6i
0.0620.5i
0.2101.8i
0.0700.6
0.2957.5i
0.0982.5i
Tap 3
SLG
All units
on
0.1891.6i
0.0630.5i
0.2061.7i
0.0690.6i
0.2987.0i
0.0992.3i
Tap 3
SLG
All units
on
0.1901.6i
0.0630.5i
0.2081.8i
0.0690.6i
0.2967.5i
0.0992.5i
Tap 3
SLG
All units
on
0.3342.4i
0.1110.8i
0.2171.9i
0.0720.6i
0
0
Tap 1
SLG
0.2001.6i
0.0670.5i
Tap 1
SLG
Tap 1
SLG
0.0812.3i
0.0650.5i
0.0812.3i
0.0792.5i
0.0690.6i
SLG
0.2447.0i
0.1951.6i
0.2446.9i
0.2377.4i
0.2061.7i
Tap 3
All units
on
All units
on
All units
on
All units
on
Tap 3
SLG
All units
on
All units
on
Unit 3 &
5 off
only
Units 2,
4 & 6 off
only
Units 2
,4 & 6
off only
Units 1,
3 & 5 off
only
Units 4,
5 & 6 off
only
Units 1,
& 3 on
only
Unit 1
on only
Unit 1
on only
Unit 1
on only
Units 2,
4, & 6
off only
0.1891.6i
0.0630.5i
0.2061.7i
Fault
Location
Fault
Type
Tap 1
SLG
Tap 1
UTY.
BUS
UTY.
BUS
DLG
Tap 3
Alt.
Plant
Bus
Off
Off
Off
Off
SLG
SLG
On
Off
Tap 3
off
Off
Tap 3
off
Off
Tap 3
off
Off
Tap 1
off
Off
Tap 3
off
Off
Tap 3
off
Off
Tap 3
off
Tap 3
off
Tap 3
off
Tap 1
off
Off
Off
Off
Off
Tap 1
off
Fault Current Distribution (in pu)
0
0
0
0
0
0
0
0
0
0
0
0
0.2987.0i
0.0992.3i
0.0690.6i
Note: Alt. = Alternate plant, Uty. = Utility, Mar. = Marriot plant, SS = Station Service
97
System Configuration
Tap
Tap 1
off
ALT.
1 and
3 off
ALT.
1 and
3 off
SS
Load
Off
Fault Current Distribution (in pu)
Fault
Location
Fault
Type
Alterna
te plant
Units
UTY
BUS
SLG
All units
on
Tap 1
SLG
Tap 1
SLG
All units
off
Unit 3
& 4 off
only
Tap 3
SLG
All units
on
Tap 1
SLG
Tap 1
SLG
Tap 3
UTY
BUS
SLG
Off
Off
Off
Tap 1
off
Off
Tap 1
off
Tap 1
off
Tap 1
off
Tap 1
off
Tap 1
off
Tap 1
off
Tap 1
off
Line
2 3I0
Line
2 I0
Line
3 3I0
Line
3 I0
0.2283.1i
0.0761i
0.2553.2i
0.0851.1i
0.2482.8i
0.0830.9i
0.2377.5i
0.0792.5i
0.2141.8i
0.0710.6i
0.2091.7i
0.0700.6i
0.2377.5i
0.0792.5i
0.2141.8i
0.0710.6i
0.2091.7i
0.700.6i
0.1931.7i
0.0640.6i
0.2101.7i
0.0700.6i
0
0
0.0782.5i
0.0782.5i
0.0650.6i
0.0781i
0.1070.8i
0.1924.0i
0.1070.8i
0.2111.8i
0.0700.6i
0
0
0
0
0
0
0
0
0
0
0
0.3442.5i
0.3532.7i
0.3442.5i
0
0.1150.8i
0.1180.9i
0.1150.8i
0
0.62811.0i
0.3252.3i
0.62811.0i
0
0.2093.7i
0.1080.8i
0.2093.7i
0.0460.2i
0.9937.7i to
plant
0.1330.7i
0.0440.2i
0.1510.8i
2.72520.6i
to
plant
0.0500.3i
0.1310.7i
0.0440.2i
0.1430.8i
2.76721.2i
to
plant
0.0480.3i
Tap 3
SLG
Tap 1
SLG
Tap 3
SLG
HY E
Section
SLG
All units
on
All units
on
HY Mid
Section
SLG
All units
on
All units
on
0.1400.8i
0.0470.3i
0.1390.7i
2.97923.0i to
plant
SLG
All units
on
All units
on
0.0420.2i
0.1440.8i
0.0480.3i
HY E
Section
SLG
All units
on
All units
on
0.1270.7i
2.79620.4i
to
plant
HY Mid
Section
SLG
All units
on
All units
on
0.1480.9i
0.0490.3i
0.1460.8i
2.97923.0i to
plant
0.0490.3i
0.9937.7i to
plant
HY W
Section
SLG
All units
on
All units
on
0.1280.7i
0.0430.2i
0.1370.7i
0.0460.2i
SLG
Off
Off
Tap 3
off
Line
1 I0
0.2347.5i
0.2357.4i
0.1951.7i
0.2333i
0.3212.4i
0.57611.9i
0.3212.4i
2.84021.0i
to
plant
Off
On
Off
Line
1 3I0
All units
on
All units
on
All units
on
All units
on
All units
on
All units
on
All units
on
Off
Off
Marriot
plant
units
Units 2,
4, & 6
off only
Units 2,
4, & 6
off only
Units 2,
4, & 6
off only
Units 1
& 3 on
only
Units 1
& 3 on
only
Unit 1
on only
Unit 1
on only
Unit 1
on only
All units
on
All units
on
All units
on
0.9477.1i to
plant
Off
Tap 3
off
Off
Tap 3
off
HY W
Section
Off
Tap 1
off
0.9326.3i to
plant
Off
Tap 1
off
Off
Tap 1
off
0.9086.9i to
plant
0.9227.1i
Note: Alt. = Alternate plant, Uty. = Utility, Mar. = Marriot plant, SS = Station Service
98
Tap
SS
Load
Off
Tap 3
off
System Configuration
Alternate
Fault
Fault
plant
Bus
Type
Units
HY
Mid
All units
Section
SLG
on
Off
Tap 1
off
All units
on
Line 1
3I0
Line 1
I0
Line 2
I0
Line 3
3I0
Line 3
I0
0.0280.2i
Line 2
3I0
2.92122.6i to
plant
0.0850.5i
0.9747.5i
0.0940.6i
0.0310.2i
2.74621.1i
0.9156.7i
0.0900.5i
0.0300.2i
0.0820.5i
0.0270.2i
0.0800.5i
0.0270.2i
0.0840.5i
0.0280.2i
2.71720.9i
0.9067.0i
All units
on
0.4184.3i
0.1391.4i
0.4605.0i
0.1531.7i
0.4464.7i
0.1491.6i
HY E
Section
SLG
HY W
Section
SLG
UTY
BUS
SLG
All units
on
Units 1
and 2 on
only
UTY
BUS
SLG
All units
on
All units
on
0.2536.4i
0.0842.1i
0.2836.7i
0.0942.2i
0.39810.9i
0.1333.6i
Off
UTY
BUS
SLG
All units
off
All units
on
0.2516.8i
0.0842.3i
0.2837.1i
0.0942.4i
0.2856.7i
0.0952.2i
On
UTY
BUS
SLG
All units
off
Units 5
& 6 off
only
0.2556.7i
0.0852.2i
0.2867.1i
0.0952.4i
0
0
On
UTY
BUS
SLG
All units
off
Unit 1 on
only
0.0571.8i
0.0190.6i
0
0
0
On
UTY
BUS
SLG
All units
off
Unit 3 on
only
0
0
0.0210.6i
0
0
On
UTY
BUS
SLG
All units
off
Unit 5 on
only
0
0
0
0.0681.7i
0.0952.4i
0
Off
Tap 1
off
Off
Tap 3
off
Tap 1
off,
Uty.
load
off
Uty.
load
off
Uty.
load
off,
Tap 1
on
UTY.
load
off,
Tap 3
on
UTY.
load
off,
Tap 1
on
UTY.
load
off,
Tap 1
on
Tap 1
and 3
off,
UTY.
load
off
Fault Current Distribution (in pu)
Marriot
plant
units
Units 2
& 5 off
only
Units 4
& 5 off
only
Units 1
& 3 off
only
Off
Off
UTY.
BUS
SLG
All units
off
Units 5
& 6 off
only
0.2536.7i
0.0842.2i
0
0.0621.8i
0
0.2857.1i
0.0230.6i
Note: Alt. = Alternate plant, Uty. = Utility, Mar. = Marriot plant, SS = Station Service
0
99
Table B.2: 3-Phase Fault Study Data
System Configuration
Alternate
Fault
Fault
Plant
Bus
Type
Units
All units
UTY
3
on
bus
phase
Tap
SS
Load
tap
1 on
No
tap
1 on
All on
UTY
bus
3
phase
tap
3 on
No
UTY
bus
3
phase
tap
3 on
tap
1 on
tap
3 on
tap
3 on
All on
All on
All on
UTY
bus
Alt.
plant
Alt.
plant
3
phase
3
phase
3
phase
All units
on
All units
on
All units
on
All units
on
All units
on
Marriot
Plant
Units
All
units
on
All
units
on
All
units
on
All
units
on
Unit 2
off
only
Unit 6
off
only
Line 1 Marriot
to Tap
Fault Current Distribution (in pu)
Line 1 - Line 2 - Line 3 Tap to
From
Marriot
Line 3 Alt.
Marriot to tap
Tap to Alt
0.1495.8i
0.0762.6i
0.1465.9i
0.1505.8i
0
0.1525.8i
0.0802.6i
0.1465.9i
0.1505.8i
0
0.1465.9i
0
0.1465.9i
0.1535.8i
0.075-2.6i
0.1495.9i
0
0.1465.9i
0.1535.8i
0.080-2.6i
0.1893.6i
0.1903.5i
0
0.1893.6i
0.0752.4i
0.0772.4i
0.1903.6i
4.64462.3i
0
4.64262.3i
No
Note: Alt. = Alternate plant, Uty. = Utility, Mar. = Marriot plant, SS = Station Service
100
APPENDIX C
SYSTEM DIAGRAMS
101
102
103
104
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